UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended September 30, 2012 | |
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: 001-34664
INERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 43-1918951 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112
(Address of principal executive offices) (Zip Code)
(816) 842-8181
(Registrant’s telephone number including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class | Name of Each Exchange on Which Registered | |
Common Units representing limited partnership interests | The New York Stock Exchange | |
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x
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 website, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer ¨ | |||
Non-accelerated filer ¨ | (Do not check if a smaller reporting company) | Smaller reporting company ¨ | ||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of March 30, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $1.7 billion based on a closing price of $16.37 per common unit as reported on the New York Stock Exchange on such date.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents are incorporated by reference into the indicated parts of this report: None.
GUIDE TO READING THIS REPORT
The following information should help you understand some of the conventions used in this report. Throughout this report,
(1) | When we use the terms “we,” “us,” “our,” “our company,” “Inergy,” or “Inergy, L.P.,” we are referring either to Inergy, L.P., the registrant itself, or to Inergy, L.P. and its wholly-owned operating subsidiaries collectively, as the context requires. |
(2) | When we use the term “Inergy Propane,” we are referring to Inergy Propane, LLC itself, or to Inergy Propane, LLC and its operating subsidiaries collectively, as the context requires. We contributed Inergy Propane to Suburban Propane Partners, L.P. in August 2012. |
(3) | When we use the term “Inergy Midstream,” we are referring to Inergy Midstream, L.P. itself, or to Inergy Midstream, L.P. and its operating subsidiaries collectively, as the context requires. As of September 30, 2012, we own an approximate 75% ownership interest in, and 100% of the incentive distribution rights of, Inergy Midstream. |
(4) | When we use the term “general partner,” we are referring to Inergy GP, LLC. |
INERGY, L.P.
INDEX TO ANNUAL REPORT ON FORM 10-K
Page | ||
Mine Safety Disclosures | ||
GLOSSARY
The terms below are common to our industry and used throughout this report.
/d | per day |
Balancing services | Services pursuant to which natural gas storage customers pay fees to help balance and true up their deliveries to, or takeaways of natural gas from, storage facilities. |
Barrel (bbl) | One barrel of petroleum products equal to 42 U.S. gallons. |
Base gas | A quantity of natural gas held within the confines of the natural gas storage facility and used for pressure support and to maintain a minimum facility pressure. May consist of injected base gas or native base gas. Also known as cushion gas. |
Bcf | One billion cubic feet of natural gas. A standard volume measure of natural gas products. |
Cycle | A complete withdrawal and injection of working gas. |
Dth | One dekatherm of natural gas. |
FERC | Federal Energy Regulatory Commission. |
Firm service | Services pursuant to which customers receive an assured, or “firm”, right to (i) in the context of storage service, store product in the storage facility or (ii) in the context of transportation service, transport product through a pipeline, over a defined period of time. |
GAAP | Generally Accepted Accounting Principles. |
Gas storage capacity | The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Gas storage capacity excludes base gas. |
Hub | Geographic location of a natural gas storage facility and multiple pipeline interconnections. |
Hub services | With respect to our natural gas operations, the following services: (i) interruptible storage services, (ii) firm and interruptible park and loan services, (iii) interruptible wheeling services, and (iv) balancing services. |
Injection rate | The rate at which a customer is permitted to inject natural gas into a natural gas storage facility. |
Interruptible service | Services pursuant to which customers receive only limited assurances regarding the availability of (i) with respect to natural gas storage services, capacity and deliverability in storage facilities or (ii) with respect to natural gas transportation services, capacity and deliverability from receipt points to delivery points. Customers pay fees for interruptible services based on their actual utilization of the storage or transportation assets. |
Local distribution companies (LDCs) | The local gas utility companies that transport natural gas from interstate and intrastate pipelines to retail and industrial customers through small-diameter distribution pipelines. |
Liquefied natural gas (LNG) | Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times. |
Mcf | One thousand cubic feet of natural gas. We have converted throughput numbers from a heating value number to a volumetric number based upon a conversion factor of 1 MMbtu equals 1 Mcf. |
MMbtu | One million British thermal units, which is approximately equal to one Mcf. One British thermal unit is equivalent to an amount of heat required to raise the temperature of one pound of water by one degree. |
MMcf | One million cubic feet of natural gas. |
Natural gas | A gaseous mixture of hydrocarbon compounds, the primary one being methane, but other components include ethane, propane and butane. |
Natural Gas Act | Federal law enacted in 1938 that established the FERC's authority to regulate interstate pipelines. |
Natural gas liquids (NGLs) | Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities). |
Park and loan services | Services pursuant to which natural gas storage customers receive the right to store natural gas in (park), or borrow natural gas from (loan), storage facilities on a seasonal basis. |
Reservoir | An underground formation that originally contained crude oil or natural gas, or both. |
Salt cavern | A man-made cavern developed in a salt dome or salt beds by leaching or mining of the salt. |
Wheeling | The transportation of natural gas from one pipeline to another pipeline through the pipeline facilities of a natural gas storage facility. The gas does not flow into or out of actual storage, but merely uses the surface facilities of the storage operation. |
Wheeling services | Services pursuant to which natural gas customers pay fees for the limited right to move a volume of natural gas from one interconnection point through storage and redelivering the natural gas to another interconnection point. |
Withdrawal rate | The rate at which a customer is permitted to withdraw gas from a natural gas storage facility. |
Working gas | Natural gas in a storage facility in excess of base gas. Working gas may or may not be completely withdrawn during any particular withdrawal season. |
Working gas storage capacity | See gas storage capacity (above). |
PART I
Item 1. Business.
Introduction
Inergy, L.P. is a publicly-traded Delaware limited partnership formed in March 2001. We own and operate energy midstream infrastructure and an NGL marketing, supply and logistics business. We are headquartered in Kansas City, Missouri, and our common units representing limited partner interests are listed on the New York Stock Exchange under the symbol “NRGY”.
Our midstream infrastructure business consists of storage and transportation operations, which are conducted primarily through Inergy Midstream, L.P. ("Inergy Midstream"), a predominantly fee-based, growth-oriented master limited partnership that develops, acquires, owns and operates natural gas and NGL storage and transportation infrastructure. Our NGL marketing, supply and logistics business utilizes our West Coast processing, fractionation and storage operations and other NGL facilities that we own or control. We have two reporting segments: (i) storage and transportation, which includes our natural gas storage assets in Texas and our approximately 75% ownership interest and incentive distribution rights ("IDRs") in Inergy Midstream (NYSE: NRGM); and (ii) NGL marketing, supply and logistics operations.
On August 1, 2012, we completed the contribution of our retail propane operations to Suburban Propane Partners, L.P. ("SPH"). We received approximately 14.2 million SPH common units with a market and book value of approximately $590 million, substantially all of which we distributed to our unitholders in September 2012. SPH also exchanged approximately $1.19 billion of our outstanding senior notes for $1.0 billion of new SPH senior notes and paid cash directly to tendering note holders. As a result of this transaction, we have repositioned our company to create a pure-play midstream company and deleveraged our balance sheet.
Our primary business objective is to increase the cash distributions that we pay to our unitholders. We expect to increase our cash flow that may be distributed to unitholders predominantly through our investment in Inergy Midstream (including our ownership of Inergy Midstream's IDRs) and, to a lesser extent, by growing our existing natural gas and NGL businesses.
On November 3, 2012, Inergy Midstream entered into an agreement to acquire Rangeland Energy, LLC (“Rangeland Energy”) for $425 million, subject to certain performance goals and working capital adjustments. Rangeland Energy owns and operates an integrated crude oil rail and truck terminal, storage and pipeline facilities (the “COLT Hub”) located in Williams County, North Dakota in the heart of the Bakken and Three Forks shale oil-producing region. The Colt Hub primarily consists of 720,000 barrels of crude oil storage, two 8,700-foot unit train rail loading loops, an eight-bay truck unloading rack, and 21-mile bi-directional crude oil pipeline that connects the terminal to crude oil gathering systems and crude oil interstate pipelines. We expect Inergy Midstream to complete the Rangeland Energy acquisition in calendar 2012.
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Ownership Structure
The diagram below reflects a simplified version of our ownership structure:
We formed Inergy Midstream, LLC in 2004 to develop, acquire, own and operate natural gas and other midstream assets. In November 2011, we converted Inergy Midstream, LLC into a Delaware limited partnership named Inergy Midstream, L.P. On December 21, 2011, Inergy Midstream completed its initial public offering.
Our Assets
Storage and Transportation
Our storage and transportation segment includes our Tres Palacios natural gas storage facility and our investment in Inergy Midstream.
We own and operate the Tres Palacios natural gas storage facility, a high performance, multi-cycle salt dome storage facility located approximately 100 miles outside of Houston in Matagorda and Wharton Counties, Texas. Tres Palacios, which is owned and operated by our subsidiary, Tres Palacios Gas Storage LLC ("TPGS"), has approximately 38.4 Bcf of certificated working gas capacity and is expandable by up to an additional 9.5 Bcf of working gas capacity. Tres Palacios is connected to 10 intrastate and interstate pipelines offering connectivity to multiple demand markets in Texas as well as the Northeast, Midwest, Southeast and Florida. Tres Palacios has placed three storage caverns into service, and we expect to place a fourth cavern into service in 2015. As of September 30, 2012, 83% of Tres Palacios's available storage capacity is contracted on a firm or interruptible basis. We acquired this storage facility on October 14, 2010.
We own an approximate 75% limited partnership interest and all the IDRs in Inergy Midstream. Inergy Midstream owns and operates four high-performance natural gas storage facilities located in New York and Pennsylvania that have an aggregate working gas storage capacity of approximately 41.0 Bcf, which we believe makes Inergy Midstream the largest independent natural gas storage provider in the Northeast. Its storage facilities have low maintenance costs, long useful lives and comparatively high cycling capabilities. The interconnectivity of its storage facilities with interstate pipelines offers flexibility to shippers in the Northeast, and the facilities are located in close proximity to the Northeast demand market and a prolific
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supply source, the Marcellus shale. Inergy Midstream's natural gas storage facilities, all of which generate fee-based revenues, include:
• | Stagecoach, a multi-cycle, depleted reservoir storage facility located approximately 150 miles northwest of New York City in Tioga County, New York and Bradford County, Pennsylvania. Stagecoach, which is owned and operated by Central New York Oil And Gas Company, L.L.C. ("CNYOG"), has 26.25 Bcf of certificated working gas capacity. Its 24-mile, 30-inch diameter south pipeline lateral connects the storage facility to Tennessee Gas Pipeline's ("TGP") 300 Line, and its 10-mile, 20-inch diameter north pipeline lateral connects to the Millennium Pipeline ("Millennium"). As of September 30, 2012, 100% of Stagecoach's available storage capacity is contracted; |
• | Thomas Corners, a multi-cycle, depleted reservoir storage facility in Steuben County, New York. Thomas Corners, which is owned and operated by Arlington Storage Company, LLC ("ASC"), has 7.0 Bcf of certificated working gas capacity. Its 8-mile, 12-inch diameter pipeline lateral connects the storage facility to TGP's 400 Line, and its 7.5-mile, 8-inch diameter pipeline lateral connects to Millennium. As of September 30, 2012, 100% of Thomas Corners' available storage capacity is contracted; |
• | Steuben, a single-turn, depleted reservoir storage facility in Schuyler County, New York. Steuben, which is owned and operated by Steuben Gas Storage Company ("Steuben Gas Storage"), has 6.2 Bcf of certificated working gas capacity. Its 12.5-mile, 12-inch diameter pipeline lateral connects the storage facility to the Dominion Transmission Inc. ("Dominion") system, and a 6-inch diameter pipeline measuring less than one mile connects Inergy Midstream's Steuben and Thomas Corners storage facilities. As of September 30, 2012, 100% of Steuben's available storage capacity is contracted; and |
• | Seneca Lake, a multi-cycle, bedded salt storage facility in Schuyler County, New York. Seneca Lake, which is owned and operated by ASC, has 1.45 Bcf of certificated working gas capacity. Its 19-mile, 16-inch diameter pipeline lateral connects the storage facility to Millennium and Dominion's system. Inergy Midstream acquired the Seneca Lake facility from New York State Electric & Gas Corporation ("NYSEG") on July 13, 2011. As of September 30, 2012, 100% of Seneca Lake's available storage capacity is contracted. |
The following provides additional information about these natural gas storage facilities:
Facility Name/ Location | Cycling Capability (Number of Cycles per Year) | Certificated Working Gas Storage Capacity (Bcf) | Maximum Injection Rate (MMcf/d) | Maximum Withdrawal Rate (MMcf/d) | Pipeline Connections | |||||||||||
Tres Palacios Matagorda and Wharton Counties, TX | 7x | 38.4 | 1,000 | 2,500 | Multiple(1) | |||||||||||
Stagecoach Tioga County, NY; Bradford County, PA | 2x | 26.25 | 250 | 500 | TGP's 300 Line; Millennium; Transco's Leidy Line(2) | |||||||||||
Thomas Corners Steuben County, NY | 2x | 7.0 | 70 | 140 | TGP's 400 Line; Millennium; Dominion(3) | |||||||||||
Seneca Lake Schuyler County, NY | 12x(4) | 1.45 | 72.5 | 145 | Dominion; Millennium | |||||||||||
Steuben Steuben County, NY | 1x | 6.3 | 30 | 60 | TGP's 400 Line; Millennium; Dominion(5) | |||||||||||
Total | 79.4 | 1,422.5 | 3,345 | |||||||||||||
(1) | Tres Palacios is interconnected to Florida Gas Transmission Company, LLC, Kinder Morgan Tejas Pipeline, L.P., Houston Pipe Line Company, Central Texas Gathering System, Natural Gas Pipeline Company of America, Transcontinental Gas Pipe Line Corporation ("Transco"), TGP, Valero Natural Gas Pipe Line Company, Channel Pipeline Company, and Texas Eastern Transmission, L.P. |
(2) | Stagecoach's south lateral will be connected to Transco's Leidy Line as a result of the MARC I Pipeline. |
(3) | Thomas Corners is connected to Dominion indirectly through the Steuben facility. |
(4) | Seneca Lake was designed for 12-turn service, but we operate it as a nine-turn high-deliverability storage facility. |
(5) | Steuben is connected to TGP and Millennium indirectly through the Thomas Corners facility. |
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Inergy Midstream also owns and operates the Bath storage facility, a 1.5 million barrel NGL storage facility located near Bath, New York. The facility is located approximately 210 miles northwest of New York City. It is supported by both rail and truck terminal facilities capable of loading and unloading 23 railcars per day and approximately 70 truck transports per day. The Bath storage facility generates fee-based revenues, and as of September 30, 2012, we control 100% of its available storage under a five-year contract expiring in 2016.
Inergy Midstream also owns and operates gas transportation facilities located in New York and Pennsylvania. These facilities have low maintenance costs and long useful lives, and they are located in or near the Marcellus shale. Throughput on Inergy Midstream's transportation assets can also be expanded at relatively low capital costs. Inergy Midstream's natural gas transportation facilities include:
• | North-South Facilities, which include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The bi-directional facilities, which are owned and operated by CNYOG, provide 325 MMcf/d of firm interstate transportation service to shippers. The North-South Facilities, which were placed into service on December 1, 2011, generate fee-based revenues under a negotiated rate structure authorized by the FERC; |
• | MARC I Pipeline, a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the Stagecoach south lateral and TGP's 300 Line in Bradford County, Pennsylvania, with Transcontinental Gas Pipe Line Company, LLC's ("Transco") Leidy Line in Lycoming County, Pennsylvania. The bi-directional pipeline, which is owned and operated by CNYOG, will provide 550 MMcf/d of interstate transportation capacity. It includes a 16,360 horsepower gas-fired compressor station in the vicinity of the Transco interconnection, and a 15,000 horsepower electric-powered compressor station at the proposed interconnection between the Stagecoach south lateral and TGP's 300 Line. Inergy Midstream expects to place the MARC I Pipeline into service on December 1, 2012, and it will generate fee-based revenues under a negotiated rate structure authorized by the FERC; and |
• | East Pipeline, a 37.5 mile, 12-inch diameter natural gas intrastate pipeline located in New York which transports 30 MMcf/d of natural gas from Dominion to the Binghamton, New York city gate. The pipeline, which is owned and operated by Inergy Pipeline East, LLC ("IPE"), runs within three miles of the Stagecoach north lateral's point of interconnection with Millennium. The East Pipeline generates fee-based revenues under a negotiated rate structure authorized by the New York State Public Service Commission ("NYPSC"). Inergy Midstream acquired the East Pipeline (formerly known as the Seneca Lake east pipeline) from NYSEG on July 13, 2011 as part of its acquisition of the Seneca Lake natural gas storage facility. |
The following provides additional information about Inergy Midstream's transportation facilities:
Facility Name | Pipeline Diameter (Inches) | Design Capacity (MMcf/d) | Pipeline Connections | |||
North-South Facilities | 20 (North lateral); 30 (South lateral) | 560 (North lateral); 728 (South lateral) | Millennium (North lateral); TGP's 300 Line (South lateral) | |||
MARC I Pipeline (1) | 30 | 550 | Stagecoach South Lateral; TGP's 300 Line; Transco's Leidy Line | |||
East Pipeline | 12 | 30 | Dominion | |||
(1) | The MARC I Pipeline has not been placed into full commercial service. |
In addition, Inergy Midstream owns US Salt, an industry-leading solution mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York. US Salt is strategically located in close proximity to Inergy Midstream's Seneca Lake natural gas storage facility and Watkins Glen NGL storage development project. It is one of five major solution mined salt manufacturers in the United States, producing evaporated salt products for food, industrial, pharmaceutical and water conditioning uses. US Salt produces and sells more than 300,000 tons of evaporated salt each year, and the solution mining process used by US Salt creates salt caverns that can be converted into natural gas and NGL storage capacity.
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NGL Marketing, Supply and Logistics
We own and operate an NGL business located near Bakersfield, California, which includes a 24.0 million gallon NGL storage facility, a 25.0 MMcf/day natural gas processing plant, a 12,000 barrels per day NGL fractionation plant, an 8,000 barrels per day butane isomerization plant, and NGL rail and truck terminals. Our West Coast operations provide NGL processing, storage, transportation and marketing services to producers, refiners and other customers.
We own and operate the Seymour storage facility, which has 21 million gallons of underground NGL storage capacity and 1.2 million gallons of aboveground “bullet” storage capacity. Located in Seymour, Indiana, the facility's receipts and deliveries are supported by TE Products Pipeline ("TEPPCO") pipeline and truck access.
We also own and operate a wholesale supply, marketing and logistics business providing NGL procurement, transportation and supply and price risk management services to independent dealers, multistate marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution companies.
Our NGL marketing, supply and logistics operations include a truck fleet, truck terminals and truck maintenance facilities. The transportation of NGLs requires specialized equipment, and our trucks carry specialized steel tanks that maintain NGLs in a liquefied state. As of September 30, 2012, we own (i) a fleet of 275 tractors and 452 transports; (ii) terminal facilities including the South Jersey Terminal in Bridgeton, New Jersey, and (iii) truck maintenance facilities in Indiana, Ohio and Mississippi.
Growth Projects
We are pursuing multiple growth projects related to our Tres Palacios storage facility, including:
• | NGL storage - effective January 1, 2012, we acquired a “call” right that enables us to store NGLs in certain storage caverns in service today near our Tres Palacios facility, as well as rights of first use for new NGL storage caverns developed on certain properties on the Markham salt dome. We expect to utilize these rights as greater volumes of NGLs are produced from the Eagle Ford shale and other plays in and around Texas, and we are pursuing commercial opportunities using caverns subject to our NGL storage rights. |
• | System enhancements - we are working to extend the Tres Palacios header system by approximately 20 miles to interconnect with Copano's Houston Central gas processing plant in Colorado County, Texas. This extension is expected to allow shippers to move gas along 60 miles of large-diameter header pipe with access to a combination of 10 interstate and intrastate pipelines and the Tres Palacios facility. We expect to receive this year the FERC authorization necessary to commence construction, and we plan to complete the expansion project in calendar 2013. We believe our customers will continue to support projects that enhance connectivity and offer greater storage and transportation services. |
• | Natural gas expansions - Texas Brine, which leases to us the mineral and surface rights we rely upon to operate the Tres Palacios storage facility, is debrining a fourth cavern located in close proximity to Tres Palacios' existing three natural gas storage caverns. We expect to place this fourth cavern into natural gas storage service after the cavern is converted from brine production into storage service. However, because this fourth cavern may be converted into NGL storage capacity, we have the flexibility to pursue the type of storage capacity that the market demands the most. |
Inergy Midstream is pursuing numerous projects, including both expansions and greenfield development projects, designed to further build out and interconnect its platform of Northeast natural gas and NGL assets, which we expect to increase its operating scale and enhance our profitability.
MARC I Pipeline
In August 2010, Inergy Midstream requested FERC authorization to construct, own and operate the MARC I Pipeline, a 39-mile bi-directional interstate natural gas pipeline that runs through Bradford, Sullivan and Lycoming Counties, Pennsylvania. Before doing so, Inergy Midstream entered into binding precedent agreements with four shippers under which they agreed to subscribe for 550 MMcf/d of firm transportation service on the MARC I Pipeline for a period of 10 years. At that time, Inergy Midstream expected to receive a FERC certificate order authorizing its pipeline by mid-summer 2011 and to place the pipeline into service by July 2012. Inergy Midstream's development plans have taken longer than anticipated due to regulatory delays and legal challenges, however, and the MARC I Pipeline is scheduled to be placed into service on December 1, 2012. As of September 30, 2012, Inergy Midstream has incurred aggregate capital costs of approximately $213.5 million for development and construction of the MARC I Pipeline.
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In October 2012, the MARC I shippers requested that their volumetric commitments be reduced from 550 MMcf/d to 450 MMcf/d. Under Inergy Midstream's precedent agreements, the shippers could terminate their contractual obligations if the pipeline was not placed into service on or before October 1, 2012. In October 2012, Inergy Midstream executed agreements with the MARC I shippers under which, among other things, (i) the shippers' volumetric requirements were permanently reduced from 550 MMcf/d to 450 MMcf/d and (ii) the shippers agreed not to terminate their contracts if the MARC I Pipeline is placed into service on or before January 1, 2013. Inergy Midstream has received FERC authorization to place the pipeline into interim service and is working to complete the final commissioning activity before requesting FERC authorization to place the pipeline into full commercial service on December 1, 2012. Inergy Midstream expects to sell all or substantially all of the 100 MMcf/d of turned-back capacity at or near rates payable by the releasing MARC I shippers. If Inergy Midstream is unable to sell any such capacity on a firm basis under long-term contracts, then it expects to sell the capacity on an interruptible basis until market conditions support the execution of long-term contracts at acceptable rates.
Watkins Glen NGL Storage Development Project
Inergy Midstream is developing a 2.1 million barrel NGL storage facility near Watkins Glen, New York, using existing cavern capacity created by US Salt's solution-mining process. Propane and butane are expected to be stored in these caverns seasonally. The facility will be supported by rail and truck terminal facilities capable of loading and unloading 32 railcars per day and 45 truck transports per day, and will connect with TEPPCO's NGL interstate pipeline. Inergy Midstream has entered into a five-year contract with us under which we will effectively market the facility's storage capacity for Inergy Midstream's economic benefit under a pass-through revenue arrangement.
Inergy Midstream filed an application with the New York State Department of Environmental Conservation ("NYSDEC") for an underground storage permit in October 2009, and it has encountered delays in the permitting process. Inergy Midstream believes it has provided all of the information the NYSDEC requires to issue the requested permit, and it expects to receive the requested permit early next year. Subject to receiving the requested permit and barring any other unexpected delays, it expects to construct and place into service the NGL storage facility within 120 days after receiving its underground storage permit. As of September 30, 2012, Inergy Midstream has incurred approximately $44.9 million of aggregate capital costs for the Watkins Glen NGL storage development project.
Truck Rack Expansion and Upgrade
In November 2012, Inergy Midstream completed construction of a new truck loading and unloading facilities at its Bath NGL storage facility. The new truck rack has two bays and arms capable of loading and unloading 70 trucks per day. Inergy Midstream is also upgrading the existing truck rack to increase the rack's loading and unloading capabilities from 17 trucks to 30 trucks per day, which it expects to complete in December 2012. Upon completion of the upgrade, Inergy Midstream's truck racks at the Bath facility are expected to be able to load and unload up to 100 trucks per day. As of September 30, 2012, Inergy Midstream has incurred approximately $0.9 million of total capital costs for this project. The affiliate that utilizes and markets all of the Bath storage capacity, Inergy Services, will pay higher annual reservation fees as a result of the new truck rack.
Commonwealth Pipeline Project
In February 2012, Inergy Midstream announced plans to jointly market and develop a new interstate natural gas pipeline project with affiliates of UGI Corporation and WGL Holdings, Inc. The Commonwealth Pipeline project is designed to provide a direct, cost-effective basis for moving Marcellus shale gas to growing natural gas demand markets in southeastern Pennsylvania and the Mid-Atlantic markets. The project sponsors held a non-binding open season for capacity on the Commonwealth Pipeline late in the second quarter of calendar 2012. Based on the results of the open season and subsequent discussions with potential shippers, the project sponsors on September 20, 2012 announced that, among other things, (i) the pipeline is expected to run approximately 120 miles to the southern terminus of Inergy Midstream's MARC I Pipeline to a point of interconnection with several interstate pipelines in Chester County, Pennsylvania; (ii) the 30-inch diameter pipeline will have an initial capacity of 800 MMcf/d of natural gas; (iii) affiliates of UGI Corporation and WGL Holdings have entered into binding precedent agreements to subscribe for firm transportation service on the Commonwealth Pipeline at negotiated rates under 10-year contracts; and (iv) the sponsors expect to place the pipeline into service in 2015.
The project sponsors are continuing to refine costs, route options and other information required to complete a feasibility study, and assess market demand for the proposed transportation capacity. Inergy Midstream remains optimistic that the market will support this low-cost transportation option for providing a direct path for moving local Marcellus shale gas to local demand centers, although we can provide no assurances that this project will be placed into service.
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Seneca Lake Expansion (Gallery 2)
Throughout fiscal 2012, Inergy Midstream continued to perform pre-construction activity and pursue the regulatory approvals required to expand the working gas capacity of its Seneca Lake natural gas storage facility by approximately 0.5 Bcf. Inergy Midstream estimates the total capital cost of this expansion to be approximately $3.0 million. Inergy Midstream has filed an application with the NYSDEC for the underground storage permit required to debrine and inject natural gas into the cavern. Upon receipt of the underground storage permit, Inergy Midstream will request FERC authorization to place the expansion capacity into natural gas storage service. Inergy Midstream expects to place this expansion capacity into service in the second half of calendar 2013.
North-South II Expansion and Extension
In September 2011, Inergy Midstream held a non-binding open season to gauge shipper interest in its North-South II expansion project, which involved the installation of pipeline, compression and other facilities to enable shippers to move higher volumes of natural gas on a firm basis through the Stagecoach laterals from TGP's 300 Line to Millennium, and all points in between. As part of this project, Inergy Midstream would (i) extend its Stagecoach north lateral approximately three miles to interconnect with the East Pipeline, which would enable shippers to transport volumes from TGP's 300 Line (as well as intermediate points, including Millennium) to the point of interconnection between the East Pipeline and Dominion's system in Tompkins County, New York, and (ii) expand the capacity of the Stagecoach laterals, by installing additional compression or looping, to enable shippers to move higher volumes over the existing pipeline route of the North-South Facilities. Inergy Midstream believes the market will desire additional transportation flexibility provided by this project and is continuing both its commercial discussions with potential shippers and its efforts to acquire the land rights necessary to complete the three-mile extension of the Stagecoach north lateral, although we can provide no assurances that this project will be placed into service.
Other Growth Projects
In May 2012, Inergy Midstream connected its Seneca Lake natural gas storage facility to Millennium. Inergy Midstream installed this interconnection at a total capital cost of approximately $7.4 million. This interconnection provides Inergy Midstream's storage customers with greater takeaway and delivery options, which it believes will translate into greater revenues from higher storage rates and increased wheeling services.
Inergy Midstream has identified existing salt caverns on US Salt's property that it believes can be converted into natural gas and NGL storage capacity. This storage capacity is in addition to the caverns designated for NGL storage by the Watkins Glen NGL storage development project and the expansion of the Seneca Lake natural gas storage facility by approximately 0.5 Bcf. In the normal course of Inergy Midstream's business, it periodically reviews cavern information to assess whether caverns are potential candidates for natural gas or NGL storage conversion, evaluates whether market demand would support developing incremental storage services, and discusses storage opportunities with potential customers. Inergy Midstream continues to believe the market will require additional natural gas and NGL storage capacity in the Northeast to help satisfy growing demand, and it believes its solution-mined caverns will be able to provide cost-effective solutions.
Our Services
Storage and Transportation
Our Tres Palacios facility provides natural gas storage services on a firm and interruptible basis, and Inergy Midstream's facilities provide storage and transportation services on a firm (natural gas and NGL) and interruptible (natural gas only) basis. We and Inergy Midstream seek to maximize the portion of physical capacity sold in our respective storage facilities under firm contracts. To the extent the physical capacity that is contracted for firm storage service is not being fully utilized, we attempt to sell the available capacity on an interruptible basis. The terms and conditions of the agreements under which our Tres Palacios storage facility provides interstate storage services, as well as the agreements under which Inergy Midstream provides interstate storage and transportation service, to customers are governed by FERC tariffs. The general terms and conditions of the tariffs address customary matters such as creditworthiness, extension and termination rights, force majeure, fuel reimbursement and capacity releases. Non-conforming service agreements must be submitted to the FERC for approval.
Firm Storage Services. Firm storage services include storage services pursuant to which customers receive an assured, or “firm,” right to store the commodity in facilities over a defined period, typically one to three years for the Tres Palacios firm storage contracts and three to five years for Inergy Midstream's natural gas firm storage contracts. Under firm storage contracts, the storage owner receives fixed monthly capacity reservation fees regardless of whether or not the storage capacity is used. The amount of the monthly reservation fees is typically determined by the number of cycles a customer can fill and
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empty its contracted storage capacity. The storage owner also typically collects a cycling fee based on the volume of natural gas nominated for injection and/or withdrawal, and retains a small portion of the gas nominated for injection as compensation for the owner's fuel use. No-notice service, which is commonly referred to as load-following service, is a premium type of firm storage service that entitles natural gas shippers to priority service and provides additional nominating and balancing flexibility.
Transportation Services. Our Tres Palacios facility does not offer transportation services, whereas Inergy Midstream provides both interstate and intrastate transportation services. Inergy Midstream's customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline capacity, the price of services and the volume and timing of the customer's requirements. Firm transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on Inergy Midstream's system. Firm customers generally pay fees based on the quantity of capacity reserved regardless of use, plus a commodity and a fuel charge paid on the volume of gas actually transported. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term. Inergy Midstream's firm transportation contracts generally range in term from five to ten years, although it may enter into shorter or longer term contracts. In providing interruptible transportation service, it agrees to transport gas for a customer when capacity is available. Interruptible transportation service customers pay a commodity charge only for the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates that change on a daily, monthly or seasonal basis.
Inergy Midstream's interstate transportation services include firm wheeling services and firm and interruptible transportation services provided under its FERC tariffs. CNYOG has entered into firm wheeling agreements with five shippers under which it is providing 325 MMcf/d of firm wheeling service to the North-South Facilities shippers at negotiated rates for an initial five-year period. CNYOG has entered into firm transportation agreements with four shippers under which it will, upon placement of the MARC I Pipeline into service, provide 450 MMcf/d of firm transportation service to the MARC I shippers at negotiated rates for an initial 10-year period. The East Pipeline provides intrastate transportation services to NYSEG under a firm transportation service agreement approved by the NYPSC. Under this 10-year contract agreement, Inergy Midstream makes 30 MMcf/d of transportation capacity available to NYSEG on the East Pipeline for transporting natural gas from Dominion's system to NYSEG's city gates.
Hub Services. With respect to our Tres Palacios storage operations and Inergy Midstream's natural gas storage and transportation operations, hub services include: (i) interruptible storage services, under which customers receive only limited assurances regarding the availability of capacity and deliverability in storage facilities and pay fees based on their actual utilization of the storage assets; (ii) firm and interruptible park and loan services, under which customers receive the right to store gas in (park), or borrow gas from (loan), storage facilities on a short-term or seasonal basis; (iii) interruptible wheeling services, under which customers pay fees for the limited right to move a volume of natural gas from one interconnection point through storage and redelivering the natural gas to another interconnection point; and (iv) balancing services, under which customers pay the storage owner fees to help balance and true up their deliveries of natural gas to, or takeaways of natural gas from, storage facilities.
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The table below summarizes the storage and transportation services that our Tres Palacios facility and Inergy Midstream offer to natural gas customers under their FERC tariffs, as of September 30, 2012:
Facility (FERC-Certificated Operator) | ||||||||||||
Type of Service | Category of Service(1) | Stagecoach (CNYOG) | Thomas Corners (ASC) | Seneca Lake (ASC) | Steuben (Steuben Gas)(2) | Tres Palacios (TPGS) | ||||||
Firm Storage Service | Firm S/S | Ÿ | Ÿ | Ÿ | Ÿ | Ÿ | ||||||
Interruptible Storage Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | Ÿ | ||||||
No-Notice Storage Service | Firm S/S | Ÿ | Ÿ | Ÿ | Ÿ | |||||||
Firm Parking Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | |||||||
Interruptible Parking Service | Hub | Ÿ | Ÿ | Ÿ | ||||||||
Firm Loan Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | |||||||
Interruptible Loan Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | |||||||
Firm Wheeling Service | Transport | Ÿ | ||||||||||
Interruptible Wheeling Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | Ÿ | ||||||
Enhanced Interruptible Wheeling Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | |||||||
Firm Transportation Service(3) | Transport | Ÿ | ||||||||||
Interruptible Transportation Service | Transport | Ÿ | ||||||||||
Interruptible Hourly Balancing Service | Hub | Ÿ | Ÿ | Ÿ | Ÿ | |||||||
(1) "Firm S/S" refers to firm storage services, "Hub" refers to hub services and "Transport" refers to transportation services
(2) Pro forma for pending merger of Steuben Gas Storage with and into ASC.
(3) Assumes the MARC I Pipeline is placed into service.
US Salt's products are manufactured for food, industrial, pharmaceutical and water conditioning applications. US Salt produces evaporated salt products for customers according to customized specifications, and its product line includes food-grade salt, pharmaceutical-grade salt, bulk salt for chemical feedstock, water softening pellets, pool salt and salt blocks. US Salt does not market and distribute products under its own brand. When US Salt enters into long-term contracts, it attempts to secure minimum volumetric purchase requirements and other appropriate contractual protections. US Salt has entered into a limited number of long-term contracts under which it has agreed to provide a fixed volume of product to the customer at certain times over the life of the contract, subject to standard contractual protections like force majeure rights.
For the year ended September 30, 2012, approximately 30% of our gross profit was derived from our storage and transportation operations. Excluding the retail propane operations that we disposed of on August 1, 2012, approximately 68% of our gross profit would have been derived from our storage and transportation operations for the year ended September 30, 2012.
NGL Marketing, Supply and Logistics
Our West Coast NGL operations separate NGLs from methane, deliver methane to the local natural gas pipelines, and retain NGLs for further processing at our fractionation facility. The mixed NGLs delivered to our fractionation facility from domestic natural gas processing plants and crude oil refineries are normally transported by pipelines, railcars and transport trucks. Our West Coast business also provides butane isomerization and refrigerated storage services. Our isomerization facility chemically changes normal butane to isobutane, which we provide to area refineries for motor fuel blending.
We provide a menu of marketing, supply and logistics services to producers, refiners, petrochemical companies, gas processors, and other NGL marketers, which effectively provide "flow assurance" to our customers. These flow assurance services offer customers certainty that production and supply NGL volumes effectively flow without interruption and at attractive economic values.
For the year ended September 30, 2012, approximately 70% of our gross profit was derived from our NGL marketing, supply and logistics operations including the results of our retail propane operations that we disposed of on August 1, 2012. Excluding the retail propane operations, approximately 32% of our gross profit would have been derived from our NGL marketing, supply and logistics operations for the year ended September 30, 2012.
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Our Customers
Storage and Transportation
Our Tres Palacios natural gas storage customers and Inergy Midstream's natural gas storage and transportation customers primarily include natural gas LDCs, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing companies. Our Tres Palacios facility provides storage services, and Inergy Midstream provides storage and transportation services, in both natural gas supply and demand markets. The customers of our Tres Palacios facility and Inergy Midstream's natural gas storage and transportation facilities are largely investment-grade customers. Natural gas storage and transportation customers that are unrated or non-investment grade may be required to post credit support as authorized under the operating entity's FERC tariffs and policies to secure a portion of the customers' obligations.
US Salt customers are largely creditworthy industrial companies, pharmaceutical companies, food manufacturing companies, and distribution companies, including retail companies such as national grocer chains.
NGL Marketing, Supply and Logistics
The majority of our NGL processing and fractionation activities entail processing mixed NGL streams for third-party customers and supporting our NGL marketing activities under contractual and fee-based arrangements. These fees (typically calculated in cents per gallon) are subject to adjustment for changes in certain fractionation expenses, including natural gas fuel costs. Our integrated midstream energy asset system affords us flexibility in meeting our customers' needs. While many companies participate in the natural gas processing business, few have a presence in significant downstream activities, such as NGL fractionation, transportation and marketing, as we do. Our competitive position and presence in these downstream businesses allow us to extract incremental value while offering our customers enhanced services, including comprehensive service packages.
Industry Background
The midstream sector of the natural gas industry provides the link between exploration and production and the delivery of natural gas and its components to end-use markets. The midstream sector consists generally of gathering and processing, transportation and storage activities.
Natural Gas Midstream Activities
The fundamentals of the natural gas market create a basic demand for storage. Natural gas is produced at a relatively steady rate throughout the year so natural gas supply is relatively constant. However, natural gas consumption is highly seasonal because the market consumes more natural gas in the winter than can be produced. In contrast, more natural gas is produced in the summer than is consumed, which creates this fundamental need for storage. Natural gas storage acts as the balancing mechanism between supply and demand.
Natural gas storage plays a vital role in maintaining the reliability of natural gas supplies needed to meet consumer demands. Storage facilities are used by pipelines to balance operations, by end users (such as power generation companies and local gas distribution companies) to manage volatility and secure natural gas supplies, and by independent natural gas marketing and trading companies in connection with the execution of their trading strategies. Storage allows for the warehousing of natural gas and is used to inject excess production during periods of low demand (typically, warmer summer months) and to withdraw natural gas during periods of high demand (typically, colder winter months).
As is the case with natural gas storage, natural gas transportation pipelines play a vital role in ensuring gas supplies find a market (i.e., moving supply to demand). Transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.
A recent shift in supply sources, from conventional to unconventional, has affected the supply patterns, the flows and the rates that can be charged on pipeline systems. The impacts will vary among pipelines according to the location and the number of competitors attached to these new supply sources. These changing market dynamics are prompting midstream companies to evaluate the construction of short-haul pipelines as a means of providing demand markets with cost-effective access to newly-developed production regions, as compared to relying on higher-cost, long-haul pipelines that were originally designed to transport natural gas greater distances across the country.
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Demand for natural gas storage can be negatively impacted during periods in which there is a narrow seasonal spread between current and future natural gas prices. The natural gas industry is currently experiencing a significant shift in the sources of supply with prolific new shale plays primarily, and this dramatic change could affect our operations.
NGL Midstream Activities
Natural gas produced at the wellhead typically contains methane and various NGLs. Raw natural gas containing NGLs is generally not acceptable for transportation in the interstate pipeline system or for commercial use. Processing plants extract the NGLs, leaving residual dry gas that meets interstate pipeline and commercial quality specifications. NGL fractionation facilities separate mixed NGL streams into discrete products: propane, normal butane, isobutane and pentanes (sometimes referred to as natural gasoline). NGL storage facilities store mixed NGLs and discrete NGL products parties in aboveground storage tanks or underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles.
Purity products (propane, normal butane, isobutane and natural gasoline) are normally used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline, and by industrial and residential users as fuel. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Common uses of isobutane include blendstock in motor gasoline to enhance the octane content and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline, denaturant for ethanol and dilute for heavy crude oil.
Current industry dynamics are resulting in increased domestic drilling targeting NGLs, particularly in areas with unconventional reserves, creating the need for additional NGL infrastructure and services. Factors contributing to this include (i) a strong crude oil and NGL price environment relative to current natural gas prices, with the price of West Texas Intermediate crude oil at $92.19/bbl, Henry Hub spot prices for natural gas at $3.06/MMBTU and composite NGL prices at $0.93/gallon each as of September 30, 2012; (ii) the continuation of oil and natural gas exploration and production innovation including geophysical interpretation, horizontal drilling and well completion techniques; (iii) a trend toward increased drilling in oil, condensate and NGL rich, or “liquids rich” reservoirs, especially resource plays; and (iv) increasing supply levels of mixed NGLs coupled with strong demand from petrochemical complexes and exports, which are leading to higher capacity utilization of NGL storage facilities. We believe these trends will continue to result in strong demand for the services provided by our NGL businesses.
Salt Activities
According to the Salt Institute, a North American based non-profit salt industry trade association, more than 290 million metric tons of salt were produced in the world in calendar 2011. Salt is generally categorized into four types based upon the method of production: evaporated salt, solar salt, rock salt and salt in brine. Dry salt is produced through the following methods: solution mining and mechanical evaporation, solar evaporation or deep-shaft mining. US Salt produces salt using solution mining and mechanical evaporation. In solution mining, wells are drilled into salt beds or domes and then water is injected into the formation and circulated to dissolve the salt. After salt is removed from a solution-mined salt deposit, the empty cavern can be used to store other substances, such as natural gas, NGLs or compressed air.
The salt solution, or brine, is next pumped out of the cavern and taken to a processing plant for evaporation. The brine may be treated to remove minerals and then pumped into vacuum pans in which the brine is boiled, and evaporated until a salt slurry is created. The slurry is then dried and separated. Depending on the type of salt product to be produced, iodine and an anti-caking agent may be added to the salt. Most food grade table salt is produced in this manner.
Regulation
The midstream operations of our company and Inergy Midstream are subject to extensive regulation by federal, state and local authorities. The regulatory burden on these operations increases the cost of doing business and, in turn, affects profitability. We have experienced increased and more burdensome regulatory oversight over the past few years and, based on our expectation that this trend will continue for the foreseeable future, we anticipate that greater time and resources will be required to obtain the approvals necessary to acquire, develop, and construct midstream infrastructure. We believe the regulatory environment for Inergy Midstream's projects located in the Northeast is particularly challenging, as public opposition to upstream oil and gas activities has increasingly influenced regulatory processes.
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We believe our operations are in substantial compliance with existing federal, state, and local laws and regulations (including the laws and regulations described below), and that our on-going compliance with applicable law will not have a material adverse effect on our business or results of operations. However, we can provide no assurance that the adoption of new laws and regulations will not add significant costs that could have a material adverse effect on our or Inergy Midstream's operations and financial results, or that our results from operations will not be materially and adversely impacted if regulations become more stringent in general. Our inability to obtain or maintain any material permit required to operate or expand our projects, or the inability of Inergy Midstream to obtain or maintain any material permits required to operate or expand its projects, could have an adverse impact on our revenues.
Natural Gas Storage and Transportation
Our natural gas storage operations, as well as the natural gas storage and transportation operations of Inergy Midstream, are subject to extensive federal and state regulation. In particular, our Tres Palacios facility and Inergy Midstream's natural gas storage and transportation facilities are subject to regulation by the FERC, and natural gas pipelines (including storage lateral pipelines) are subject to regulation by the Department of Transportation's ("DOT") Pipeline and Hazardous Materials Safety Administration ("PHMSA").
Under the Natural Gas Act, the FERC has authority to regulate gas transportation services in interstate commerce, which includes natural gas storage services. The FERC exercises jurisdiction over rates charged for services and the terms and conditions of service; the certification and construction of new facilities; the extension or abandonment of services and facilities; the maintenance of accounts and records; the acquisition and disposition of facilities; standards of conduct between affiliated entities; and various other matters. Regulated natural gas companies are prohibited from charging rates determined by the FERC to be unjust, unreasonable, or unduly discriminatory, and both the existing tariff rates and the proposed rates of regulated natural gas companies are subject to challenge.
The rates and terms and conditions of our natural gas storage services and Inergy Midstream's natural gas storage and transportation services are found in the FERC-approved tariffs of TPGS, the owner of the Tres Palacios facility; CNYOG, the owner of the Stagecoach facility, the North-South Facilities and the MARC I Pipeline; Steuben Gas Storage, the owner of the Steuben facility; and ASC, the owner of the Thomas Corners and Seneca Lake facilities. TPGS, CNYOG and ASC are authorized to charge and collect market-based rates for storage services provided at the Tres Palacios, Stagecoach, Thomas Corners and Seneca Lake natural gas storage facilities, and CNYOG is authorized to charge and collect negotiated rates for transportation services provided by the North-South Facilities and MARC I Pipeline. Steuben Gas Storage is authorized to charge and collect cost-of-service rates at the Steuben facility. Market-based and negotiated rate authority allows storage and transport owners to negotiate rates with individual customers based on market demand, which storage and transport owners then make public. A loss of market-based or negotiated rate authority or any successful complaint or protest against the rates charged or provided by TPGS, CNYOG or ASC could have an adverse impact on our revenues.
On December 20, 2011, we filed an application with the FERC (Docket No. CP12-36) requesting authority for the Copano header extension project. On October 9, 2012, the FERC issued an Environmental Assessment for the project in which the FERC Staff has proposed a “finding of no significant impact”. We expect to receive the requested authorization this year, and to complete the header extension project in calendar 2013.
On August 6, 2010, CNYOG filed an application with the FERC (Docket No. CP10-480) requesting authority to construct, operate and own the MARC I Pipeline. On November 14, 2011, the FERC issued a certificate order granting the requested authorization. On February 13, 2012, the FERC issued an order denying or dismissing all requests for rehearing of the certificate order and a request for stay of that order.
On February 14, 2012, certain of the parties seeking rehearing of the MARC I certificate order filed with the Second Circuit Court of Appeals an appeal and emergency motion for stay of the MARC I certificate. A temporary stay was granted on February 17, 2012, which halted all construction-related activity on the Pipeline until a three-judge panel vacated the temporary stay on February 28, 2012. In March, the Second Circuit granted the request for an expedited hearing briefing schedule for the MARC I certificate appeal. On June 12, 2012, the appellate court held that the FERC properly discharged its responsibilities and summarily dismissed with prejudice petition challenging the MARC I certificate and rehearing orders.
On May 21, 2012, Inergy Midstream filed applications with the FERC (Docket Nos. CP12-465 and CP12-466) requesting authority (i) to abandon the FERC tariff held by Steuben Gas Storage and (ii) for ASC to acquire the Steuben facility, via the merger of Steuben Gas Storage into ASC, and to charge marketed-based rates under ASC's tariff for services at the Steuben facility. On October 11, 2012, the FERC issued an order granting the requested authorizations. Effective April 1, 2013, ASC will have the ability to charge market-based rates for storage service provided by its Thomas Corners, Seneca Lake and Steuben
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facilities and to provide wheeling services under one tariff (ASC's tariff). Thomas Corners will also effectively be connected to Dominion, and Steuben will effectively be connected to TGP and Millennium, with respect to services offered under ASC's tariff. These actions move Inergy Midstream closer toward its goal of developing and operating a fully-integrated natural gas storage and transportation hub in the Northeast.
Pipelines used to store and transport natural gas are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968 ("NGPSA"). The NGPSA regulates safety requirements in the design, installation, testing, construction, operation and maintenance of natural gas pipeline facilities. The NGPSA has since been amended by the Pipeline Safety Act of 1992, the Pipeline Safety Improvement Act of 2002, and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. These amendments, along with implementing regulations more recently adopted by PHMSA, have imposed additional safety requirements on pipeline operators such as the development of a written qualification program for individuals performing covered tasks on pipeline facilities and the implementation of pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventative measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways.
Notwithstanding the investigatory and preventative maintenance costs incurred performing routine pipeline management activities, we may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards as a result of new or amended legislation. For example, in January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline safety regulations from $1 million to $2 million. PHMSA is also considering changes to its natural gas transmission pipeline regulations to, among other things, expand the scope of "high consequence areas", strengthen integrity management requirements applicable to existing operators; strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and add new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection or withdrawal well piping that are not regulated today. Inergy Midstream cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new requirements may have on its business.
The natural gas operations of Tres Palacios and Inergy Midstream are also subject to non-rate regulation by various state agencies. For example, the Railroad Commission of Texas ("RRC") has jurisdiction over oil and gas wells drilled and produced, underground natural gas storage caverns and related facilities and pipelines used to transport oil and gas resources in Texas, and the NYSDEC has jurisdiction over the underground storage of natural gas and well drilling, conversion and plugging in New York. Accordingly, the RRC regulates aspects of our Tres Palacios storage operations and the NYSDEC regulates aspects of the Stagecoach, Thomas Corners, Seneca Lake and Steuben storage facilities.
IPE, as the owner and operator of Inergy Midstream's East Pipeline, is subject to lightened regulation under NYPSC regulations and policies. Lightened regulation generally exempts IPE from NYPSC regulation applicable to the provision of retail service. IPE remains subject to limited corporate (e.g., obtaining approval prior to any transfer of its ownership interests or the issuance of debt securities) and operational and safety (e.g., filing of vegetation management plan and annual reports detailing the gas volumes transported over the pipeline) regulation established and maintained by the NYPSC.
On September 15, 2011, IPE filed an application with the NYPSC (Docket No. 11-G-0510) requesting authority to pledge its equity interests in collateral support of, and to guarantee, up to $3 billion of our long-term indebtedness. The application described that, upon completion of Inergy Midstream's initial public offering, the scope of the requested authorization would be limited to pledges and guarantees supporting up to $1.5 billion of long-term indebtedness of Inergy Midstream and its wholly-owned subsidiaries. On December 15, 2011, the NYPSC issued an order granting the requested authorization.
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NGL Storage and Transportation
NGL storage operations are subject to federal, state and local regulatory oversight. For example, the Indiana Department of Natural Resources ("INDNR") and the NYSDEC have jurisdiction over the underground storage of NGLs and well drilling, conversion and plugging in Indiana and New York, respectively. Thus, the INDNR regulates aspects of our Seymour facility, and the NYSDEC regulates aspects of Inergy Midstream's Bath facility and its proposed Watkins Glen facility.
In October 2009, Inergy Midstream filed an application with the NYSDEC for an underground storage permit for its Watkins Glen NGL storage facility. In November 2010, the NYSDEC issued a Positive Declaration for the project. In August 2011, the NYSDEC determined that the Draft Supplemental Environmental Impact Statement submitted for the project was complete. A public hearing on the project was held in September 2011, and a second public hearing was held in November 2011. In early 2012, based on concerns expressed by interested stakeholders and conversations with NYSDEC Staff, Inergy Midstream informed the NYSDEC that it would reduce the environmental footprint and modified our brine pond design. In September 2012, Inergy Midstream submitted to the NYSDEC all final drawings and plans for the revised project design. Inergy Midstream expects the NYSDEC to issue an underground storage permit early next year.
Our transportation of NGLs and ammonia by truck is subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with application regulations, and we believe that our procedures for transporting NGLs and ammonia are consistent with industry standards and in compliance in all material respects with applicable law.
Salt Production
US Salt's salt production and manufacturing business is highly regulated. Under the Food, Drug and Cosmetic Act, the United States Food and Drug Administration regulates food and pharmaceutical standards applicable to salt products for human consumption and drug products. The United States Environmental Protection Agency ("EPA") administers regulations for emissions control under a Title V air permit, operation and control of solution mining operations, and stormwater pollution prevention for petroleum products. The NYSDEC regulates the drilling and plugging of brine production wells, cooling/process water intake, and wastewater and stormwater discharges. The NYSDEC also administers regulations for bulk petroleum and chemical storage.
Environmental, Health and Safety
In addition, our operations and those of Inergy Midstream are subject to stringent federal, regional, state and local laws and regulations governing the discharge and emission of pollutants into the environment, environmental protection, or occupational health and safety. These laws and regulations may impose significant obligations on our operations, including the need to obtain permits to conduct regulated activities; restrict the types, quantities and concentration of materials that can be released into the environment; apply workplace health and safety standards for the benefit of employees; require remedial activities or corrective actions to mitigate pollution from former or current operations; and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the activities in a particular area.
The following is a summary of the more significant existing environmental laws and regulations, each as amended from time to time, to which our business operations are subject:
• | The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, a remedial statute that imposes strict liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur; |
• | The federal Resource Conservation and Recovery Act, which governs the treatment, storage and disposal of solid wastes, including hazardous wastes; |
• | The federal Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements; |
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• | The federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters; |
• | The federal Safe Drinking Water Act, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controlling the injection of substances into below-ground formations that may adversely affect drinking water sources; |
• | The National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment; |
• | The federal Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and |
• | The federal Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures. |
Certain of these environmental laws impose strict, joint and several liability for costs required to clean up and restore properties where pollutants have been released regardless of whom may have caused the harm or whether the activity was performed in compliance with all applicable laws. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal. In addition, many of the properties owned or leased by us were previously operated by third parties whose management, disposal or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. Private parties, including the owners of properties that we lease and facilities where our materials or wastes are taken for recycling or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. We may not be able to recover some or any of these additional costs from insurance.
We have not received any notices that we have violated these environmental laws and regulations in any material respect and we have not otherwise incurred any material liability or capital expenditures thereunder. Future developments, such as stricter environmental laws or regulations, or more stringent enforcement of existing requirements could affect our operations. For instance, the EPA and other federal and state agencies are considering or have already commenced the study of potential adverse impacts that certain drilling methods (including hydraulic fracturing) may have on water quality and public health, with the U.S. Department of Energy having released a report recommending the implementation of a variety of measures to reduce the environmental impacts from shale-gas production. Similarly, Congress and several states, including New York and Pennsylvania, have proposed or enacted legislation or regulations that are expected to make it more difficult or costly for exploration and production companies to produce natural gas and NGLs. These initiatives, enactments and regulations could have an indirect adverse impact on us by decreasing demand for the storage and transportation services that we offer.
In addition, federal and state occupational safety and health laws require us to organize information about materials, some of which may be hazardous or toxic, that are used, released, or produced in the course of our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-to-Know Act requirements. Our operations are also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.
Competition
The principal elements of competition among our Tres Palacios facility and Inergy Midstream's storage and transportation assets are rates, terms of service, types of service, supply and market access, and flexibility and reliability of service. An increase in competition in our markets or Inergy Midstream's markets could arise from new ventures or expanded operations from existing competitors.
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Principal competitors in the natural gas storage market include other independent storage providers and major natural gas pipelines. These major pipeline natural gas transmission companies have existing storage facilities connected to their systems that compete with our Tres Palacios facility and Inergy Midstream's facilities. The FERC has adopted a policy that favors authorization of new storage projects, and there are numerous natural gas storage options in Tres Palacios' geographic market and Inergy Midstream's geographic market. Pending and future construction projects, if and when brought on line, may also compete with our natural gas storage operations and Inergy Midstream's natural gas storage operations. These projects may include FERC-certificated storage expansions and greenfield construction projects.
Inergy Midstream's primary competitors in the NGL storage business include integrated major oil companies, refiners and processors, and other pipeline and storage companies.
Our NGL marketing, supply and logistics business encounters competition from fully integrated oil companies and independent NGL marketing companies. Our competitors have varying levels of financial and personnel resources, and competition generally revolves around price, service and location.
Our salt operations compete for customers primarily based on price and service. Because transportation costs are a material component of the costs our customers pay, most of our customers are geographically located east of the Mississippi River.
Employees
As of October 31, 2012, we had 653 full time employees. Of the 653 employees, 117 were general and administrative and 536 were operational. As of October 31, 2012, US Salt had 140 employees, 105 of which are members of a labor union. We believe that our relationship with our employees (including union labor) is satisfactory.
Available Information
Our website is located at www.inergylp.com. We make available, free of charge, on or through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the Securities and Exchange Commission ("SEC"). These documents are also available, free of charge, at the SEC's website at www.sec.gov. In addition, copies of these documents, excluding exhibits, may be requested at no cost by contacting Investor Relations, Inergy, L.P., Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112, and our corporate telephone number is (816) 842-8181.
We also make available within the “Corporate Governance” section of our website our corporate governance guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics. Requests for copies may be directed in writing to: Inergy, L.P., Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112, Attention: General Counsel. Interested parties may contact the chairperson of any of our Board committees, our Board's independent directors as a group or our full Board in writing by mail to Inergy, L.P., Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri, 64112, Attention: General Counsel. All such communications will be delivered to the director or directors to whom they are addressed.
Item 1A. Risk Factors
Risks Inherent in Our Structure and Relationship with Inergy Midstream
Our primary cash-generating assets are our partnership interests, including incentive distribution rights, in Inergy Midstream, and our cash flow is therefore materially dependent upon the ability of Inergy Midstream to make distributions in respect to those partnership interests to its partners.
The amount of cash that Inergy Midstream can distribute to its partners each quarter, including us, principally depends upon the amount of cash Inergy Midstream generates from its operations, which amounts of cash may fluctuate from quarter to quarter based on, among other things:
• | the rates Inergy Midstream charges for storage and transportation services and the amount of services their customers purchase from Inergy Midstream, which will be affected by, among other things, the overall balance between the supply of and demand for natural gas, governmental regulation of Inergy Midstream's rates and services, and Inergy Midstream's ability to obtain permits for growth projects; |
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• | force majeure events that damage Inergy Midstream or third-party pipelines, facilities, related equipment and surrounding properties; |
• | prevailing economic and market conditions; |
• | governmental regulation, including changes in governmental regulation in our industry; |
• | leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise; |
• | difficulties in collecting receivables because of customers' credit or financial problems; and |
• | changes in tax laws. |
In addition, the actual amount of cash Inergy Midstream will have available for distribution will depend on other factors, some of which are beyond its control, including: the level and timing of capital expenditures it makes; the cost of acquisitions; its debt service requirements and other liabilities; fluctuations in its working capital needs; its ability to borrow funds and access capital markets; restrictions contained in its debt agreements; and the amount of cash reserves established by its general partner.
We do not have control over many of these factors, including the level of cash reserves established by the board of directors and Inergy Midstream's general partner. Accordingly, we cannot guarantee that Inergy Midstream will have sufficient available cash to pay a specific level of cash distributions to its partners.
If Inergy Midstream reduced its per unit distribution, we would have less cash available for distribution and would probably be required to reduce our per unit distribution. Furthermore, the amount of cash that Inergy Midstream has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, Inergy Midstream may be able to make cash distributions during periods when it records losses and may not be able to make cash distributions during periods when Inergy Midstream records net income.
To the extent we purchase additional units from Inergy Midstream, our rate of growth may be reduced.
Our business strategy may include supporting the growth of Inergy Midstream by purchasing its securities or lending funds to Inergy Midstream to provide funding for acquisitions or internal growth projects. To the extent we purchase common units, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of Inergy Midstream's IDRs, which distributions increase at a faster rate than those of our other securities.
We could have an indemnification obligation to Inergy Midstream, which could materially adversely affect our financial condition.
We have entered into an omnibus agreement with Inergy Midstream and its general partner that governs certain aspects of our relationship with them. Pursuant to the omnibus agreement, we are generally obligated to indemnify Inergy Midstream and its affiliates against certain environmental liabilities and liabilities of the assets of the operations of Inergy Midstream prior to December 21, 2011. See “Certain Relationships and Related Party Transactions-Omnibus Agreement.” Our indemnification obligations under the omnibus agreement could result in substantial expenses and liabilities to Inergy Midstream, which could materially adversely affect our financial condition. For example, we may be required to indemnify Inergy Midstream in connection with the Anadarko litigation. See “Item 3 - Legal Proceedings.”
Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect, and do not have the right to elect, our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the sole member of our general partner, Inergy Holdings, L.P. John J. Sherman, who currently is the only voting member of the general partner of Inergy Holdings, effectively has the authority to appoint all of our directors. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to Inergy, L.P. and our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its member, Inergy Holdings, L.P.
If unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of 66 2/3% of the outstanding units voting together as a single class.
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Our unitholders' voting rights are further restricted by a provision in our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partners and their affiliates, cannot be voted on any matter.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner, Inergy Holdings, L.P., from transferring its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by our board of directors and officers.
Cost reimbursements due our general partner may be substantial and reduce our ability to pay the quarterly distribution.
Before making any distributions on our units, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to you. Our general partner has sole discretion to determine the amount of these expenses and fees.
We may issue additional common units without unitholder approval, which would dilute our unitholders' existing ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of unitholders. The issuance of additional common units or other equity securities of equal rank will have the following effects:
• | the proportionate ownership interest of our existing unitholders in us will decrease; |
• | the amount of cash available for distribution on each common unit or partnership security may decrease; |
• | the relative voting strength of each previously outstanding common unit will be diminished; and |
• | the market price of the common units or partnership securities may decline. |
Future sales of the Inergy Midstream common units we own or other limited partner interests in the public market could reduce the market price of our unitholders' limited partner interests.
As of September 30, 2012, we owned approximately 56.4 million common units of Inergy Midstream. If we were to sell and/or distribute our Inergy Midstream common units to the holders of our equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the public markets could reduce the market price of Inergy Midstream's outstanding common units and our receipt of cash distributions.
Inergy Midstream may issue additional common units, which may increase the risk that it will not have sufficient available cash to maintain or increase its per unit distribution level.
The Inergy Midstream partnership agreement allows it to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by Inergy Midstream will have the following effects:
• | Our unitholders' current proportionate ownership interest in Inergy Midstream will decrease; |
• | the amount of cash available for distribution on each common unit or partnership security may decrease; |
• | the ratio of taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding common unit may be diminished; and |
• | the market price of Inergy Midstream's common units may decline. |
The payment of distributions on any additional units issued by Inergy Midstream may increase the risk that Inergy Midstream may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.
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If we cease to manage and control Inergy Midstream in the future, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to manage and control Inergy Midstream and are deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”) we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. For further discussion of the importance of our treatment as a partnership for federal income tax purposes and the implications that would result from our treatment as a corporation in any taxable year, please read the risk factor below entitled “The tax treatment of publicly traded partnerships is subject to potential legislative, judicial or administrative changes. If we or Inergy Midstream were treated as a corporation for federal income tax purposes, or if we or Inergy Midstream were to become subject to a material amount of state or local taxation, then our cash available for distribution to our unitholders would be substantially reduced.
In the event of a change of control, we may be obligated to transfer control of our general partner interest in Inergy Midstream to an affiliate.
We and the general partner of Inergy Holdings (“Holdings GP”) have entered into an agreement under which Holdings GP will be required to purchase the entity that controls the general partner of Inergy Midstream in the event that (i) a change of control of our partnership occurs at a time when we are entitled to receive less than 50% of all cash distributed with respect to our limited partner interests and incentive distribution rights or (ii) through dilution or a distribution to our common unitholders of our interests in Inergy Midstream, we are entitled to receive less than 25% of all cash distributed with respect to our limited partner interests and incentive distribution rights. Please read “Certain Relationships and Related Party Transactions-NRGM GP, LLC Change of Control Event.”
Although we control Inergy Midstream through our ownership of its general partner, Inergy Midstream's general partner owes fiduciary duties to Inergy Midstreams's unitholders, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and Inergy Midstream and its limited partners, on the other hand. The directors and officers of Inergy Midstream's general partner have fiduciary duties to manage Inergy Midstream in a manner beneficial to us. At the same time, the general partner has fiduciary duties to manage Inergy Midstream in a manner beneficial to Inergy Midstream and its limited partners. The board of directors of Inergy Midstream's general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
For example, conflicts of interest with Inergy Midstream may arise in the following situations:
• | the allocation of shared overhead expenses to Inergy Midstream and us; |
• | the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Inergy Midstream, on the other hand; |
• | the determination of the amount of cash to be distributed to Inergy Midstream's partners and the amount of cash to be reserved for the future conduct of Inergy Midstream's business; |
• | the determination whether to make borrowings under Inergy Midstream's revolving credit facility to pay distributions to Inergy Midstream's partners; and |
• | any decision we make in the future to engage in business activities independent of Inergy Midstream. |
The fiduciary duties of our general partner's officers and directors may conflict with those of Inergy Midstream's general partners.
Conflicts of interest may arise because of the relationships among Inergy Midstream, its general partner and us. Our general partner's directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our unitholders. Some of our general partner's directors and officers are also directors and officers of Inergy Midstream's general partner, and have fiduciary duties to manage the business of Inergy Midstream in a manner beneficial to Inergy Midstream and its unitholders. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
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Affiliates of our general partner are not prohibited from competing with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
• | Our general partner is allowed to take into account the interests of parties other than us, including Inergy Midstream and its affiliates and any general partner and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us. |
• | Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
• | Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution. |
• | Our general partner determines which costs it and its affiliates have incurred are reimbursable by us. |
• | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us. |
• | Our general partner controls the enforcement of obligations owed to us by it and its affiliates. |
• | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
Our partnership agreement limits our general partner's fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
• | provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests; |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. |
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Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 85% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of September 30, 2012, the directors and executive officers of our general partner owned less than 1% of our common units.
Our cash distribution policy limits our ability to grow.
Because we distribute all of our available cash, our growth may not be as rapid as businesses that reinvest their available cash to expand ongoing operations. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.
Risks Inherent in Our Business and Inergy Midstream's Business
Unless otherwise indicated, the risk factors in this section apply to our operations and Inergy Midstream's operations.
The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for natural gas, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting natural gas supplies has been the significant growth in unconventional sources such as shale plays. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:
• | adverse changes in general global economic conditions. The level and speed of the recovery from the recent recession remains uncertain and could impact the supply and demand for natural gas and our future rate of growth in our business; |
• | adverse changes in domestic regulations that could impact the supply or demand for natural gas; |
• | technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales; |
• | competition from imported LNG and Canadian supplies and alternate fuels; |
• | increased prices of natural gas or NGLs that could negatively impact demand for these products; |
• | increased costs to explore for, develop, produce, gather, process and transport natural gas or NGLs; |
• | adoption of various energy efficiency and conservation measures; and |
• | perceptions of customers on the availability and price volatility of our services, particularly customers' perceptions on the volatility of natural gas prices over the longer-term. |
If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated expansion activities. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, and results of operations.
If we do not complete growth projects or make acquisitions, our future growth may be limited.
Our business strategy depends on Inergy Midstream's ability to grow cash available for distribution and our ability to grow our existing businesses. Inergy Midstream's business strategy depends on its ability to complete growth projects and make acquisitions that result in an increase in cash generated from operations on a per unit basis (i.e., complete accretive
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transactions). We or Inergy Midstream may be unable to complete successful, accretive growth projects or acquisitions for any of the following reasons:
• | a failure to identify attractive expansion or development projects or acquisition candidates that satisfy acceptable economic and other criteria, or an inability to realize such opportunities as a result of being outbid by competitors; |
• | a failure to raise financing for such projects or acquisitions on economically acceptable terms; |
• | a failure to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or |
• | a failure to obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions. |
Our and Inergy Midstream's operations are subject to extensive regulation, and regulatory measures adopted by regulatory authorities could have a material adverse effect on our business, financial condition and results of operations.
Our and Inergy Midstream's operations are subject to extensive regulation by federal, state and local regulatory authorities. For example, because we transport natural gas in interstate commerce and we store natural gas that is transported in interstate commerce, our natural gas storage and transportation facilities are subject to comprehensive regulation by the FERC under the Natural Gas Act. Federal regulation under the Natural Gas Act extends to such matters as:
• | rates, operating terms and conditions of service; |
• | the form of tariffs governing service; |
• | the types of services we may offer to our customers; |
• | the certification and construction of new, or the expansion of existing, facilities; |
• | the acquisition, extension, disposition or abandonment of facilities; |
• | contracts for service between storage and transportation providers and their customers; |
• | creditworthiness and credit support requirements; |
• | the maintenance of accounts and records; |
• | relationships among affiliated companies involved in certain aspects of the natural gas business; |
• | the initiation and discontinuation of services; and |
• | various other matters. |
Natural gas companies may not charge rates that, upon review by FERC, are found to be unjust and unreasonable or unduly discriminatory. Existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be challenged and such increases may ultimately be rejected by FERC. We currently hold authority from FERC to charge and collect market-based rates for interstate storage services provided at our Tres Palacios facility. Inergy Midstream currently holds authority from FERC to charge and collect (i) market-based rates for interstate storage services provided at the Stagecoach, Thomas Corners and Seneca Lake facilities and (ii) negotiated rates for interstate transportation services provided over the North-South Facilities and the MARC I Pipeline. FERC's “market-based rate” policy allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Among the sorts of changes in circumstances that could raise market power concerns would be an expansion of capacity, acquisitions or other changes in market dynamics. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets' operating lives. Any successful challenge against rates charged for our storage and transportation services, or our loss of market-based rate authority or negotiated rate authority, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. Our market-based rate authority for our natural gas storage facilities may be subject to review and possible revocation if FERC determines that we have the ability to exercise market power in our market area. If we were to lose our ability to charge market-based rates, we would be required to file rates based on our cost of providing service, including a reasonable rate of return. Cost-of-service rates may be lower than our current market-based rates.
There can be no assurance that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.
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We may not be able to renew or replace expiring contracts.
Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As of September 30, 2012, the weighted average remaining tenor of our and Inergy Midstream's existing portfolio of firm storage contracts are approximately 1.2 and 3.4 years, respectively. Customer contracts for 11 Bcf of natural gas firm storage service will expire at our Tres Palacios facility in fiscal 2013, and customer contracts for 5.2 Bcf of natural gas firm storage service will expire at Inergy Midstream's facilities in fiscal 2013. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
• | the macroeconomic factors affecting natural gas and NGL storage economics for our current and potential customers; |
• | the level of existing and new competition to provide services to our markets; |
• | the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; |
• | the extent to which the customers in our markets are willing to contract on a long-term basis; and |
• | the effects of federal, state or local regulations on the contracting practices of our customers. |
Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
We depend on third-party pipelines connected to our storage facilities and pipelines, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such third-party pipelines.
We depend on the continued operation of third-party pipelines that provide delivery options to and from our storage facilities, and to which our transportation pipelines are connected. For example, Inergy Midstream's Stagecoach facility depends on TGP's 300 Line and Millennium, currently the only interstate pipelines to which it is directly interconnected. These pipelines are owned by parties not affiliated with us. Any temporary or permanent interruption at any key pipeline or other interconnect point with our storage facilities that causes a material reduction in the volume of storage or transportation services provided by us could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities and pipelines affect the utilization and value of our services. Significant changes in the rates charged by these pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
Expanding our business by developing new midstream assets subjects us to risks.
Our growth projects are an integral part of our business strategy. The development and construction of storage facilities, pipelines, and truck/rail terminals involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will occur over an extended period of time, and we will not receive material increases in revenues until the project is placed in service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations and ability to make distributions.
Certain of our growth projects must receive regulatory approval from federal and state authorities prior to construction, such as Inergy Midstream's Watkins Glen NGL storage development project. The approval process for storage and transportation projects has become increasingly challenging. We cannot guarantee such authorization will be granted or, if granted, that such authorization will be free of burdensome or expensive conditions.
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Acquisitions or growth projects that we complete may not perform as anticipated and could result in a reduction of our cash available for distribution.
Even if we complete projects or acquisitions that we believe will be accretive, such projects or acquisitions may nevertheless reduce our cash available for distribution due to the following factors:
• | mistaken assumptions about storage capacity, deliverability, base gas needs, geological integrity, revenues, synergies, costs (including operating and administrative, capital, debt and equity costs), customer demand, growth potential, assumed liabilities and other factors; |
• | the failure to receive cash flows from an growth project or newly acquired asset due to delays in the commencement of operations for any reason; |
• | unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or growth project was completed; |
• | the inability to attract new customers or retain acquired customers to the extent assumed in connection with the acquisition or growth project; |
• | the failure to successfully integrate growth projects or acquired assets or businesses into our operations and/or the loss of key employees; or |
• | the impact of regulatory, environmental, political and legal uncertainties that are beyond our control. |
If we complete future growth projects or acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources. If any growth projects or acquisitions we ultimately complete are not accretive to our cash available for distribution, our ability to make distributions may be reduced.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to pay cash distributions may be diminished or our financial leverage could increase.
In order to expand our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to raise the level of our cash distributions. To fund our expansion capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests. Such uses of cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
Increased competition could have a negative impact on the demand for our services, which could adversely affect our financial results.
We compete primarily with other providers of storage and transportation services that own or operate natural gas and NGL storage facilities and natural gas pipelines. Such competitors include independent storage developers and operators, LDCs, interstate and intrastate natural gas transmission companies with storage facilities connected to their pipelines, and other midstream companies. Some of our competitors have greater financial, managerial and other resources than we do and control substantially more storage and transportation capacity than we do. In addition, our customers may develop their own storage and transportation assets in lieu of using ours. FERC has adopted a policy that favors authorization of new storage projects, and there are numerous natural gas storage options in the geographic markets we serve. Pending and future construction projects, if and when brought on-line, may also compete with our natural gas storage operations. Such projects may include FERC-certificated storage expansions and greenfield construction projects.
We also compete with the numerous alternatives to storage available to customers, including pipeline balancing/no-notice services, seasonal/swing services provided by pipelines and marketers and on-system LNG facilities. Natural gas as a fuel also competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage and transportation services.
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If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct new storage or transportation assets that would create additional competition for us. The expansion of storage or transportation assets and construction activities of our competitors could result in storage or transportation capacity in excess of actual demand, which could reduce the demand for our services, and potentially reduce the rates that we receive for our services.
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and NGL storage and transportation in our markets, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
Inergy Midstream expects to derive a significant portion of its revenues from a limited number of customers, and the loss of one or more of these customers could result in a significant loss of revenues and cash flow.
Inergy Midstream expects to derive a significant portion of its revenues and cash flow from a limited number of customers. For the fiscal year ended September 30, 2012, ConEd accounted for approximately 14% of Inergy Midstream's total revenue. The loss, nonpayment, nonperformance or impaired creditworthiness of one of Inergy Midstream's large customers could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
We are exposed to the credit risk of our customers in the ordinary course of our business.
We extend credit to our customers as a normal part of our business. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies that include assessing the creditworthiness of our customers as permitted by our FERC-approved gas tariffs and requiring appropriate terms or credit support from them based on the results of such assessments, there can be no assurance that we have adequately assessed the creditworthiness of our existing or future customers or that there will not be unanticipated deterioration in their creditworthiness. Resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
Additionally, in instances where we loan natural gas to third parties, the magnitude of our credit risk is significantly increased, as the failure of the third party to return the loaned volumes would result in losses equal to the full value of the loaned natural gas rather than, in the case of firm storage or hub services contracts, losses equal to fees on volumes nominated for injection or withdrawal.
The fees charged by us to third parties under storage and transportation agreements may not escalate sufficiently to cover increases in costs, and those agreements may be suspended in some circumstances.
Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. In addition, some third parties' obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas is curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If the escalation of fees is insufficient to cover increased costs or if any third party suspends or terminates its contracts with us, our business, financial condition, results of operations and ability to make distributions could be materially adversely affected.
Our business involves many hazards and risks, some of which may not be fully covered by insurance.
Our operations are subject to all of the risks and hazards inherent in the natural gas and NGL storage and transportation businesses, including:
• | subsidence of the geological structures where we store natural gas and NGLs; |
• | risks and hazards inherent in drilling operations associated with the development of new caverns; |
• | problems maintaining the wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our storage facilities; |
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• | damage to our facilities and properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism, third parties, equipment or material failures, pipeline or vessel ruptures or corrosion, explosions and other incidents; |
• | leaks, migrations or losses of natural gas and NGLs; |
• | collapse of storage caverns; |
• | operator error; |
• | environmental hazards, such as NGL or condensate spills, pipeline and tank ruptures, drinking water contamination associated with our raw water or water disposal wells, and discharges of toxic gases, fluids or other pollutants into the surface and subsurface environment; |
• | failure to comply with environmental or pipeline safety regulatory requirements; and |
• | other industry hazards that could result in the suspension of operations. |
These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. In addition, we are not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.
As a result of these risks and hazards, we have been, and will likely be, a defendant in legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent. However, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.
In addition, we share insurance coverage with Inergy, for which we reimburse Inergy pursuant to the terms of the omnibus agreement. To the extent Inergy experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.
Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make distributions.
We have a $550 million credit facility with a maturity date in July 2016 and Inergy Midstream has a $600 million credit facility (expandable up to $750 million) with a maturity date in December 2016. Both credit facilities are available to fund working capital and growth projects, make acquisitions and for general partnership purposes.
Our and Inergy Midstream's credit facilities contain various covenants and restrictive provisions that will limit our and Inergy Midstream's ability to, among other things:
• | incur additional debt; |
• | make distributions on or redeem or repurchase units; |
• | make certain investments and acquisitions; |
• | incur or permit certain liens to exist; |
• | enter into certain types of transactions with affiliates; |
• | merge, consolidate or amalgamate with another company; and |
• | transfer or otherwise dispose of assets. |
Furthermore, our credit facility contains covenants requiring us to maintain certain financial ratios. For example, our credit facility requires maintenance of a consolidated leverage ratio (as defined in our credit agreement) of not more than 4.75 to 1.00 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.5 to 1.00. Inergy Midstream's revolving credit facility contains covenants requiring it to maintain certain financial ratios. For example, Inergy Midstream's revolving credit facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.00.
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Borrowings under our credit facility are secured by (i) pledges of the equity interests of, and guarantees by, substantially all of our existing and future domestic wholly-owned subsidiaries, and (ii) liens on substantially all of our real and personal property. Borrowings under Inergy Midstream's revolving credit facility are secured by (i) pledges of the equity interests of, and guarantees by, substantially all of its existing and future subsidiaries, and (ii) liens on substantially all of its real and personal property.
The provisions of each company's credit facility may affect its ability to obtain future financing and pursue attractive business opportunities and each company's flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of a credit facility could result in an event of default, which could enable the lenders, subject to applicable notice and cure provisions, to declare any outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of any such debt of our's is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our common units could experience a partial or total loss of their investment. If the payment of any such debt of Inergy Midstream is accelerated, its assets may be insufficient to repay such debt in full, and the holders of Inergy Midstream's common units could experience a partial or total loss of their investment.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
• | our funds available for operations, future business opportunities and distributions to common unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt; |
• | we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
• | our flexibility in responding to changing business and economic conditions may be limited. |
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
An unfavorable resolution of the Anadarko litigation could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
In June 2010, Inergy Midstream's predecessor, Inergy Midstream, LLC (“NRGM Predecessor”), and CNYOG entered into a letter of intent with Anadarko Petroleum Corporation ("Anadarko") which contemplated that, subject to certain conditions, Anadarko may exercise an option to acquire up to a 25% ownership interest in the MARC I Pipeline. On September 23, 2011, Anadarko filed a complaint against NRGM Predecessor and CNYOG in the Court of Common Pleas in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I Pipeline, (ii) NRGM Predecessor refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, NRGM Predecessor breached the letter of intent, and (iii) by refusing to enter into definitive agreements, NRGM Predecessor breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific performance of the letter of intent and monetary damages. Inergy Midstream filed its answer to Anadarko's complaint in January 2012, and discovery is continuing. An unfavorable resolution of such litigation could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, such litigation could divert the attention of management and resources in general from day-to-day operations. For further information regarding this lawsuit, please see “Item 3 -Legal Proceedings” of this Part I.
Our operations are subject to compliance with environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. Such laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable legal requirements, the application of specific health and safety criteria addressing worker protections and the imposition of
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restrictions on the generation, handling, treatment, storage, disposal and transportation of materials and wastes. Failure to comply with such laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting some or all of our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where materials or wastes have been disposed or otherwise released. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal.
It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services and salt products. It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us or our customers and also adversely affect demand for the natural gas, NGLs or salt products.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for our services.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (GHGs) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, has already adopted rules regulating GHG emissions under the Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources, which could require greenhouse emission controls for those sources. The EPA has also adopted rules requiring the reporting of GHG emissions from specified onshore oil and natural gas production, processing, transmission, storage and distribution facilities on an annual basis. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas that is produced, which may decrease demand for our storage services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.
Increases in interest rates could adversely impact demand for our storage capacity, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.
There is a financing cost for our customers to store natural gas or NGLs in our storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas or NGLs in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas or NGLs for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our common unit price is impacted by the level of our cash distributions and our implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our common unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.
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If Inergy Midstream is unable to diversify its assets and geographic locations, its ability to make distributions to Inergy Midstream's common unitholders could be adversely affected.
Inergy Midstream relies on revenues generated from storage and transportation assets that it owns, which are located exclusively in the Northeast region of the United States. Due to its lack of diversification in asset location and the storage-heavy nature of its existing asset base, an adverse development in these businesses or areas, including adverse developments due to catastrophic events, weather and decreases in demand for natural gas, could have a significantly greater impact on Inergy Midstream's results of operations and cash available for distribution to its common unitholders than if Inergy Midstream maintained more diverse assets and locations.
Inergy Midstream's growth strategy includes acquiring entities with lines of business that are distinct and separate from its existing operations, which could subject Inergy Midstream to additional business and operating risks.
Consistent with its announced growth strategy and pending acquisition of Rangeland Energy, Inergy Midstream may acquire assets that have operations in new and distinct lines of business from its existing operations. Integration of new business segments is a complex, costly and time-consuming process and may involve assets in which Inergy Midstream has limited operating experience. Failure to timely and successfully integrate acquired entities' new lines of business with its existing operations may have a material adverse effect on Inergy Midstream's business, financial condition or results of operations. The difficulties of integrating new business segments with existing operations include, among other things:
• | operating distinct business segments that require different operating strategies and different managerial expertise; |
• | the necessity of coordinating organizations, systems and facilities in different locations; |
• | integrating personnel with diverse business backgrounds and organizational cultures; and |
• | consolidating corporate and administrative functions. |
In addition, the diversion of Inergy Midstream's attention and any delays or difficulties encountered in connection with the integration of the new business segments, such as unanticipated liabilities or costs, could harm Inergy Midstream's existing business, results of operations, financial condition or prospects. Furthermore, new lines of business will subject Inergy Midstream to additional business and operating risks, which could have a material adverse effect on its financial condition or results of operations.
Inergy Midstream may be unable to successfully integrate its acquisitions.
One of Inergy Midstream's primary business strategies is to grow through acquisitions. There is no assurance that Inergy Midstream will successfully integrate acquisitions into our operations, or that Inergy Midstream will achieve the desired profitability from its acquisitions. Failure to successfully integrate these substantial acquisitions could adversely affect Inergy Midstream's operations. The difficulties of combining the acquired operations include, among other things: (i) operating a significantly larger organization; (ii) coordinating geographically disparate organizations, systems and facilities; (iii) integrating personnel from diverse business backgrounds and organizational cultures; (iv) consolidating corporate, technological and administrative functions; (v) integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters; (vi) the diversion of management's attention from other business concerns; (vii) customer or key employee loss from the acquired businesses; and (viii) potential environmental or regulatory liabilities and title problems. In addition, Inergy Midstream may not realize all of the anticipated benefits from our acquisitions, such as cost-savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher costs, unknown liabilities and fluctuations in markets.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the Exchange Act). Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, conclusions about the effectiveness of
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our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
A change of control could result in us facing substantial repayment obligations under our credit facility.
Our credit agreement contains provisions relating to change of control of our general partner and our partnership. If these provisions are triggered, our outstanding bank indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under our credit facility would have the right to foreclose on our assets, which would have a material adverse effect on us. There is no restriction on the ability of our general partners to enter into a transaction which would trigger the change of control provisions.
If we are not able to sell propane that we have purchased through wholesale supply agreements to retailers and other wholesalers, the results of our operations would be adversely affected.
We currently are party to propane supply contracts and may enter into additional propane supply contracts which require us to purchase substantially all the propane production from certain refineries. Our inability to sell the propane supply to retail propane distributors or to other propane wholesalers would have a substantial adverse impact on our operating results and could adversely impact our capital liquidity.
Our agreement with SPH exposes us to potentially significant indemnification obligations.
We have certain indemnification obligations to SPH pursuant to the agreement entered into in connection with our contribution to SPH of Inergy Propane (the “Contribution Agreement”). Under the Contribution Agreement, we have agreed to indemnify SPH for any damages arising out of any breach of our representations and warranties, our failure to perform any of our covenants or agreements, certain tax matters and certain retained liabilities. In general, our indemnification obligations are limited by an indemnification deductible of $15 million and indemnification ceiling of $150 million; provided, however, that our indemnification obligations for breach of certain fundamental representations and warranties, certain tax matters and certain retained liabilities are not subject to such limitations. In the event that SPH brings a claim for indemnification, we may be obligated to make significant payments, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
Tax Risks to Common Unitholders
The tax treatment of publicly traded partnerships is subject to potential legislative, judicial or administrative changes. If we were treated as a corporation for federal income tax purposes, or if we or Inergy Midstream were to become subject to a material amount of state or local taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. The value of our investments in Inergy Midstream depends largely on Inergy Midstream being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us or Inergy Midstream may be treated as a corporation for federal income tax purposes unless it satisfies requirements regarding the sources of its income. Based on our current operations we believe that we and Inergy Midstream are each treated as a partnership rather than a corporation; however, a change in either of our businesses could cause either of us to be treated as a corporation for federal income tax purposes.
If we or Inergy Midstream were treated as a corporation for federal income tax purposes, we each would be obligated to pay federal income tax on our respective taxable income at the corporate tax rate, currently a maximum rate of 35%, as well as any applicable state income tax. Distributions to our and Inergy Midstream's unitholders generally would be taxedin the same manner as distributions from a corporation, and none of our or Inergy Midstream's income, gain, loss, deduction or credit from us or Inergy Midstream would flow through to our respective unitholders. Because a tax would be imposed upon us or Inergy Midstream as a corporation, our respective cash available for distribution would be substantially reduced. Therefore, treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our respective unitholders, likely causing a substantial reduction in the value of our common units.
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The tax treatment of publicly traded partnerships or an investment in Inergy Midstream's or our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including Inergy Midstream and us, or an investment in Inergy Midstream's or our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we and Inergy Midstream rely on for our treatment as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in Inergy Midstream's or our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the expectation for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
Neither we nor Inergy Midstream has requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by you and our general partner because the costs will reduce our cash available for distribution.
You will be required to pay taxes on your share of our income even if you do not receive cash distributions from us.
Because you will be treated as a partner in us for federal income tax purposes, we will allocate a share of our taxable income to you which could be different in amount than the cash we distribute to you, and you may be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between your amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our total net taxable income result in a reduction in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities, regulated investment companies and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U. S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax adviser before investing in our common units.
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We and Inergy Midstream will treat each purchaser of our respective units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of Inergy Midstream's and our common units.
Because we cannot match transferors and transferees of units, we and Inergy Midstream will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of Inergy Midstream's common units and our common units and could have a negative impact on the value of our respective common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. However, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there is no tax concept of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange within a twelve-month period of 50% or more of the total interests in our capital and profits. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Pursuant to an IRS relief procedure a publicly traded partnership that has technically terminated may request special relief which, if granted by the IRS, among other things, would permit the partnership to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.
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Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and foreign taxes that are imposed by the various jurisdictions in which we do business or own property and in which they do not reside. We own property and conduct business in various parts of the United States. Unitholders may be required to file state and local income tax returns in many or all of the jurisdictions in which we do business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders' responsibility to file all required U. S. federal, state, local and foreign tax returns.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
We lease our Kansas City, Missouri headquarters. We lease the subsurface and surface rights necessary to own and operate our Tres Palacios gas storage facility under a 25-year storage sublease agreement. We also lease underground storage facilities for our NGL marketing, supply and logistics business with an aggregate capacity of 38.2 million gallons of propane and butane storage at six locations under annual lease agreements, and we lease capacity on multiple pipelines pursuant to annual agreements.
We own the following assets as discussed in Item 1:
• | facilities comprising our Tres Palacios natural gas storage facility; |
• | facilities comprising our West Coast NGL business; and |
• | our Seymour NGL storage facility. |
We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered in connection with acquisitions and immaterial encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligations under our credit facility are secured by liens and mortgages on our fee-owned real and personal property.
In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operation of our business.
Item 3. Legal Proceedings.
Our operations are subject to all operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing for use by consumers of combustible liquids. As a result, at any given time we are a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverages and deductibles as the general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
In June 2010, Inergy Midstream's predecessor ("NRGM Predecessor") and CNYOG entered into a letter of intent with Anadarko which contemplated that, subject to certain conditions, Anadarko may exercise an option to acquire up to a 25% ownership interest in the MARC I Pipeline. On September 23, 2011, Anadarko filed a complaint against NRGM Predecessor and CNYOG in the Court of Common Pleas in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I Pipeline, (ii) NRGM Predecessor refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, Inergy Midstream breached the letter of intent, and (iii) by refusing to enter into
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definitive agreements, NRGM Predecessor breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific performance of the letter of intent and monetary damages.
Inergy Midstream filed preliminary objections to the complaint and sought a judgment in its favor and an order dismissing Anadarko's complaint. Following a hearing on the motion to dismiss the Anadarko complaint on December 2, 2011, the motion was denied. Inergy Midstream filed its answer to Anadarko's complaint in January 2012 and discovery continues. Inergy Midstream believes that Anadarko's claims are without merit and intend to vigorously defend itself in the lawsuit.
Following the announcement of the Merger Agreement, two unitholder class action lawsuits were filed in the Court of Chancery of the State of Delaware challenging the proposed merger (Joel A. Gerber v. Inergy GP, LLC et al., No. 5864 and G-2 Trading LLC v. Inergy GP, LLC et al., No. 5816) (collectively, the “Inergy Unitholder Lawsuits”). The parties to the Inergy Unitholder Lawsuits have entered into a Memorandum of Understanding whereby in consideration for the settlement and dismissal of the claims, the individual Class B unitholders will forego and relinquish a total of 135,539 Class B units to be received as distributions following the date on which the settlement and dismissal becomes final and no longer appealable. On March 29, 2012, the court approved the terms of the settlement, which included the certification of a settlement class and the dismissal with prejudice of all claims. Also as part of the settlement, the defendants in the Inergy Unitholder Lawsuits other than Inergy must pay fees and expenses to counsel for the plaintiffs in the amount of $1.8 million, which amount is covered by insurance.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our common units representing limited partner interests are traded on The New York Stock Exchange ("NYSE") under the symbol “NRGY.” The following table sets forth the range of high and low bid prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per common unit for the periods indicated.
Quarters Ended: | Low | High | Cash Distribution Per Unit | ||||||||
Fiscal 2012: | |||||||||||
September 30, 2012 | $ | 17.25 | $ | 21.99 | $ | 0.290 | |||||
June 30, 2012 | 15.22 | 20.24 | 0.375 | ||||||||
March 31, 2012 | 15.06 | 24.99 | 0.375 | ||||||||
December 31, 2011 | 22.54 | 28.88 | 0.705 | ||||||||
Fiscal 2011: | |||||||||||
September 30, 2011 | $ | 24.91 | $ | 35.90 | $ | 0.705 | |||||
June 30, 2011 | 33.52 | 41.22 | 0.705 | ||||||||
March 31, 2011 | 38.49 | 42.75 | 0.705 | ||||||||
December 31, 2010 | 37.25 | 41.92 | 0.705 | ||||||||
As of November 7, 2012, we had issued and outstanding 125,645,598 common units, 4,867,252 Class A units and 5,882,105 Class B units, which were held by 188, 2 and 20 unitholders of record, respectively.
Cash Distribution Policy
Our company makes quarterly distributions to the partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. Available cash generally means, with respect to each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:
• | provide for the proper conduct of our business; |
• | comply with applicable law, any of our debt instruments, or other agreements; or |
• | provide funds for distributions to unitholders for any one or more of the next four quarters; |
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
On November 14, 2012, we paid a distribution of $0.290 per limited partner unit ($1.16 per limited partner unit on an annualized basis) to all unitholders of record on November 7, 2012.
Distribution of SPH Units
We distributed 14.1 million SPH common units on September 14, 2012.
Issuance of Class A Units and Class B Units
On November 5, 2010, in connection with the merger between us and Inergy Holdings, L.P., we issued 4,867,252 Class A units and 11,568,560 Class B units. Following the November 2011 distribution, 6,586,968 Class B units converted to Inergy common units. Following the November 2012 distribution, the remaining Class B units were converted to Inergy common units. Inergy, L.P. indirectly owns 100% of the Class A units.
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Issuer Purchases of Equity Securities
For the fiscal year ended September 30, 2012, 103,236 common units were relinquished to us to cover payroll taxes upon the vesting of restricted units.
Equity Compensation Plan Information
The following table sets forth in tabular format, a summary of equity compensation plan information as of September 30, 2012:
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted- average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||
(a) | (b) | (c) | |||||||
Equity compensation plans approved by security holders | — | — | — | ||||||
Equity compensation plans not approved by security holders | 181,541 | $ | 13.11 | 8,350,709 | |||||
Total | 181,541 | 13.11 | 8,350,709 | ||||||
Item 6. Selected Financial Data.
The following tables set forth selected consolidated financial data and other operating data of Inergy, L.P. The selected historical consolidated financial data of Inergy, L.P. as of and for the years ended September 30, 2012, 2011, 2010, 2009, and 2008, are derived from the audited consolidated financial statements of Inergy, L.P. The historical consolidated financial data of Inergy, L.P. include the results of operations of its acquisitions from the effective date of the respective acquisitions.
“EBITDA” shown in the table below is defined as income before income taxes, plus net interest expense and depreciation and amortization expense. Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses, the gain on the disposal of retail propane operations, the loss on SPH units and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
The data in the following tables should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included in this report. The tables should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Item 7.
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Inergy L.P. Years Ended September 30, (in millions, except unit and per unit data) | |||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
Statement of Operations Data: | |||||||||||||||||||
Revenues | $ | 2,006.8 | $ | 2,153.8 | $ | 1,786.0 | $ | 1,570.6 | $ | 1,878.9 | |||||||||
Cost of product sold (excluding depreciation and amortization as shown below): | 1,396.2 | 1,476.0 | 1,165.9 | 996.9 | 1,376.7 | ||||||||||||||
Expenses: | |||||||||||||||||||
Operating and administrative | 300.8 | 323.3 | 310.7 | 280.5 | 266.6 | ||||||||||||||
Depreciation and amortization | 169.6 | 191.8 | 161.8 | 115.8 | 98.0 | ||||||||||||||
Loss on disposal of assets | 5.7 | 8.2 | 11.5 | 5.2 | 11.5 | ||||||||||||||
Operating income | 134.5 | 154.5 | 136.1 | 172.2 | 126.1 | ||||||||||||||
Other income (expense): | |||||||||||||||||||
Interest expense, net | (83.6 | ) | (113.5 | ) | (91.5 | ) | (70.5 | ) | (62.6 | ) | |||||||||
Gain on disposal of retail propane operations | 589.5 | — | — | — | — | ||||||||||||||
Loss on Suburban Propane Partners, L.P. units | (47.6 | ) | — | — | — | — | |||||||||||||
Early extinguishment of debt | (26.6 | ) | (52.1 | ) | — | — | — | ||||||||||||
Other income | 1.5 | 1.2 | 2.0 | 0.1 | 1.0 | ||||||||||||||
Income (loss) before gain on issuance of units in subsidiary and income taxes | 567.7 | (9.9 | ) | 46.6 | 101.8 | 64.5 | |||||||||||||
Gain on issuance of units in subsidiary | — | — | — | 8.0 | — | ||||||||||||||
Provision for income taxes | 1.8 | 0.7 | 0.2 | 1.7 | 1.4 | ||||||||||||||
Net income (loss) | 565.9 | (10.6 | ) | 46.4 | 108.1 | 63.1 | |||||||||||||
Net (income) loss attributable to non-controlling partners | (11.0 | ) | 28.2 | 15.4 | (51.0 | ) | (27.6 | ) | |||||||||||
Net income attributable to partners | $ | 554.9 | $ | 17.6 | $ | 61.8 | $ | 57.1 | $ | 35.5 | |||||||||
Net income per limited partner unit: | |||||||||||||||||||
Basic | $ | 4.39 | $ | 0.17 | $ | 1.73 | $ | 1.62 | $ | 1.01 | |||||||||
Diluted | $ | 4.22 | $ | 0.15 | $ | 1.29 | $ | 1.21 | $ | 0.75 | |||||||||
Weighted-average limited partners’ units outstanding (in thousands): | |||||||||||||||||||
Basic | 124,976 | 105,732 | 35,726 | 35,197 | 35,049 | ||||||||||||||
Diluted | 131,589 | 117,684 | 48,002 | 47,036 | 47,106 | ||||||||||||||
Cash distributions paid per unit(a) | $ | 2.16 | $ | 2.82 | $ | 2.76 | $ | 2.60 | $ | 2.44 | |||||||||
Balance Sheet Data (end of period): | |||||||||||||||||||
Total assets | $ | 2,207.6 | $ | 3,340.9 | $ | 3,117.8 | $ | 2,154.1 | $ | 2,098.5 | |||||||||
Total debt, including current portion | 743.2 | 1,853.0 | 1,690.7 | 1,124.8 | 1,139.2 | ||||||||||||||
Total partners’ capital | 1,184.8 | 1,146.0 | 1,160.1 | 772.0 | 609.1 | ||||||||||||||
Other Financial Data: | |||||||||||||||||||
EBITDA (unaudited) | $ | 847.5 | $ | 347.5 | $ | 299.9 | $ | 296.1 | $ | 225.1 | |||||||||
Adjusted EBITDA (unaudited) | 321.5 | 372.2 | $ | 323.9 | $ | 295.9 | $ | 238.0 | |||||||||||
Net cash provided by operating activities | 239.0 | 114.4 | 173.6 | 237.9 | 180.2 | ||||||||||||||
Net cash used in investing activities | (350.6 | ) | (390.6 | ) | (926.4 | ) | (230.6 | ) | (386.7 | ) | |||||||||
Net cash provided by (used in) financing activities | 100.1 | 143.3 | 885.5 | (13.0 | ) | 216.0 | |||||||||||||
Maintenance capital expenditures(b) (unaudited) | 12.4 | 14.0 | 9.9 | 8.0 | 5.4 | ||||||||||||||
Other Operating Data (unaudited): | |||||||||||||||||||
Retail propane gallons sold | 233.5 | 325.6 | 340.2 | 310.0 | 331.9 | ||||||||||||||
NGL Marketing gallons delivered(c) | 504.3 | 395.5 | 393.7 | 357.7 | 335.0 | ||||||||||||||
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2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
Reconciliation of Net Income to EBITDA and Adjusted EBITDA: | |||||||||||||||||||
Net income (loss) | $ | 565.9 | $ | (10.6 | ) | $ | 46.4 | $ | 108.1 | $ | 63.1 | ||||||||
Interest expense, net | 83.6 | 113.5 | 91.5 | 70.5 | 62.6 | ||||||||||||||
Early extinguishment of debt | 26.6 | 52.1 | — | — | — | ||||||||||||||
Provision for income taxes | 1.8 | 0.7 | 0.2 | 1.7 | 1.4 | ||||||||||||||
Depreciation and amortization | 169.6 | 191.8 | 161.8 | 115.8 | 98.0 | ||||||||||||||
EBITDA | $ | 847.5 | $ | 347.5 | $ | 299.9 | $ | 296.1 | $ | 225.1 | |||||||||
Non-cash (gain) loss on derivative contracts | (8.6 | ) | 1.2 | (1.0 | ) | 1.4 | 0.1 | ||||||||||||
Long-term incentive and equity compensation expense | 17.9 | 5.8 | 10.9 | 3.1 | 3.5 | ||||||||||||||
Loss on disposal of assets | 5.7 | 8.2 | 11.5 | 5.2 | 11.5 | ||||||||||||||
Gain on disposal of retail propane operations | (589.5 | ) | — | — | — | — | |||||||||||||
Loss on Suburban Propane Partners, L.P. units | 47.6 | — | — | — | — | ||||||||||||||
Gain on issuance of units in subsidiary | — | — | — | (8.0 | ) | — | |||||||||||||
Transaction costs | 0.9 | 9.5 | 3.5 | — | — | ||||||||||||||
Adjusted EBITDA | $ | 321.5 | $ | 372.2 | $ | 324.8 | $ | 297.8 | $ | 240.2 | |||||||||
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA: | |||||||||||||||||||
Net cash provided by operating activities | $ | 239.0 | $ | 114.4 | $ | 173.6 | $ | 237.9 | $ | 180.2 | |||||||||
Net changes in working capital balances | (9.4 | ) | 104.1 | 60.7 | (4.4 | ) | 3.8 | ||||||||||||
Non-cash early extinguishment of debt | (10.0 | ) | (12.7 | ) | — | — | — | ||||||||||||
Provision for doubtful accounts | (2.1 | ) | (3.7 | ) | (2.8 | ) | (3.7 | ) | (5.7 | ) | |||||||||
Amortization of deferred financing costs, swap premium and net bond discount | (4.9 | ) | (7.4 | ) | (7.3 | ) | (5.2 | ) | (2.3 | ) | |||||||||
Unit-based compensation charges | (12.9 | ) | (5.8 | ) | (4.8 | ) | (3.1 | ) | (3.5 | ) | |||||||||
Loss on disposal of assets | (5.7 | ) | (8.2 | ) | (11.5 | ) | (5.2 | ) | (11.5 | ) | |||||||||
Gain on disposal of retail propane operations | 589.5 | — | — | — | — | ||||||||||||||
Loss on Suburban Propane Partners, L.P. units | (47.6 | ) | — | — | — | — | |||||||||||||
Deferred income tax | (0.4 | ) | 0.5 | 0.3 | (0.4 | ) | 0.1 | ||||||||||||
Interest expense, net | 83.6 | 113.5 | 91.5 | 70.5 | 62.6 | ||||||||||||||
Early extinguishment of debt | 26.6 | 52.1 | — | — | — | ||||||||||||||
Gain on issuance of units in subsidiary | — | — | — | 8.0 | — | ||||||||||||||
Provision for income taxes | 1.8 | 0.7 | 0.2 | 1.7 | 1.4 | ||||||||||||||
EBITDA | $ | 847.5 | $ | 347.5 | $ | 299.9 | $ | 296.1 | $ | 225.1 | |||||||||
Non-cash (gain) loss on derivative contracts | (8.6 | ) | 1.2 | (1.0 | ) | 1.4 | 0.1 | ||||||||||||
Long-term incentive and equity compensation expense | 17.9 | 5.8 | 10.9 | 3.1 | 3.5 | ||||||||||||||
Loss on disposal of assets | 5.7 | 8.2 | 11.5 | 5.2 | 11.5 | ||||||||||||||
Gain on disposal of retail propane operations | (589.5 | ) | — | — | — | — | |||||||||||||
Loss on Suburban Propane Partners, L.P. units | 47.6 | — | — | — | — | ||||||||||||||
Gain on issuance of units in subsidiary | (8.0 | ) | — | ||||||||||||||||
Transaction costs | 0.9 | 9.5 | 3.5 | — | — | ||||||||||||||
Adjusted EBITDA | $ | 321.5 | $ | 372.2 | $ | 324.8 | $ | 297.8 | $ | 240.2 | |||||||||
(a) | These amounts reflect the historical cash distributions paid per unit on the common units. |
(b) | Maintenance capital expenditures are defined as those capital expenditures that do not increase operating capacity or revenues from existing levels. |
(c) | Subsequent to the sale of Inergy's retail propane operations, the Company reorganized its operating and reporting segments. Prior year amounts have been adjusted to reflect the current year presentation. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Forward-Looking Statements
This report, including information included or incorporated by reference in this report, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performance and business of our company and its subsidiaries. These forward-looking statements include:
• | statements that are not historical in nature, but not limited to, (i) our belief that our investments and growth strategies to allow us to increase the distributions that we pay to our unitholders; (ii) our expectation that Inergy Midstream will complete its acquisition of Rangeland Energy in calendar 2012; (iii) our expectation that Inergy Midstream will place the MARC I Pipeline into service on December 1, 2012; (iv) our expectations concerning Tres Palacios' growth projects; (v) our belief that Inergy Midstream's growth projects will enhance our profitability; (v) our expectation that Inergy Midstream will obtain the permits required construct its Watkins Glen NGL storage development project and place it into service in calendar 2013; and |
• | statements preceded by, followed by or that contain forward-looking terminology including the words “believe,” “expect,” “may,” “will,” “should,” “could,” “anticipate,” “estimate,” “intend” or the negation thereof, or similar expressions. |
Forward-looking statements are not guarantees of future performance or results. They involve risks, uncertainties and assumptions. Actual results may differ materially from those contemplated by the forward-looking statements due to, among others, the following factors:
• | our ability to successfully implement our business plan for our assets and operation; |
• | governmental legislation and regulations; |
• | industry factors that influence the supply of, and demand for, natural gas and NGLs; |
• | weather conditions; |
• | industry factors that influence the demand for natural gas and NGL storage and transportation capacity, particularly in the Northeast and Texas markets; |
• | economic conditions; |
• | the availability of natural gas and NGLs, and the price of natural gas and NGLs, to consumers compared to the price of alternative and competing fuels; |
• | costs or difficulties related to the integration of our existing businesses and acquisitions; |
• | environmental claims; |
• | operating hazards and other risks incidental to transporting and storing natural gas and NGLs; |
• | interest rates; and |
• | the price and availability of debt and equity financing. |
We have described under “Risk Factors” additional factors that could cause actual results to be materially different from those described in the forward-looking statements. Other factors that we have not identified in this report could also have this effect. You are cautioned not to put undue reliance on any forward-looking statement, which speaks only as of the date it was made.
Overview
We are a publicly-traded master limited partnership that owns and operates energy midstream infrastructure and an NGL marketing, supply and logistics business. We own and operate the Tres Palacios natural gas storage facility in Texas; a proprietary NGL business that specializes in providing logistics and marketing services predominantly to producers and refiners; and approximately 75% ownership interest in Inergy Midstream, a publicly-traded, growth-oriented master limited partnership with midstream facilities located in the Northeast region of the United States.
Our Company
With the disposition of our retail propane business in August 2012, we have transformed our company into a “pure play” midstream energy company with significant investments in the natural gas and NGL sectors of the energy value chain. Our Tres Palacios facility is located near the liquids-rich Eagle Ford shale play and Texas demand markets, and through Inergy Midstream, we have significant investments in natural gas storage and transportation facilities located near the Marcellus shale play and the Northeast demand market. We believe our NGL business complements our infrastructure investments, and the
39
combination of the expertise and proprietary knowledge developed by our NGL marketing, supply, transportation and risk management professionals and our fleet of NGL transportation assets provides a competitive advantage over our competitors.
Our primary business objective is to increase the cash distributions that we pay to our unitholders by growing our investment in Inergy Midstream and, to a lesser extent, growing our Texas storage operations and NGL business. We intend to position Inergy Midstream to be able to increase its cash distributions by providing strong general partner support (including, if applicable, selling assets to Inergy Midstream) and using it as the primary vehicle through which we grow our midstream business. We expect to grow our Tres Palacios operations through development projects, such as the Copano header extension project, and we believe the facility's strategic location to the Eagle Ford shale play and interconnections with 10 interstate and intrastate pipelines will allow us to capture greater revenue opportunities as natural gas prices and volatility increase. We anticipate growing our NGL marketing, supply, and logistics business by continuing to leverage our industry knowledge, expertise and relationships to develop and harvest business opportunities and to expand our service offerings. We will continuously evaluate the best way to grow our company and unlock value for our unitholders.
Our business segments include (i) storage and transportation, which includes our Tres Palacios natural gas storage facility and our investment in Inergy Midstream, and (ii) NGL supply, marketing and logistics reporting segment, which includes our NGL business. The cash flows from our Tres Palacios facility are predominantly fee-based under one to three year contracts with creditworthy counterparties. The cash flows from our NGL supply, marketing and logistics operations represent sales to creditworthy customers typically under contracts that are less than one year in duration, and these cash flows tend to be seasonal in nature due to our customer profiles and their tendencies to purchase NGLs during peak winter periods.
As a result of our disposition of our retail propane operations, a majority of our distributable cash flows are expected to be generated by distributions received from Inergy Midstream and cash from operations generated by our Tres Palacios facility and NGL business. Our natural gas storage revenues are driven in large part by competition and demand for our storage capacity and deliverability, although demand for firm storage service in Texas remains depressed due to low natural gas prices and low seasonal spreads. Our NGL segment revenues are driven in large part by our ability to optimize NGL assets that we own or control, and provide services to producers, refiners and other customers which effectively provide flow assurance to our customers. These services offer customers certainty of NGL production and supply volumes flowing without interruption and at attractive economic value.
Our long-term profitability will be influenced primarily by (i) Inergy Midstream's ability to execute on its growth strategy, including both development projects and strategic acquisitions, and to increase cash available for distribution; (ii) our ability to execute growth strategies for our Tres Palacios facility and NGL business; (iii) our ability to contract and re-contract with customers; and (iv) our ability to manage increasingly difficult regulatory processes, particularly in permitting and approval proceedings at the federal and state levels.
With respect to market trends, the assets comprising our storage and transportation segment (including the infrastructure assets of Inergy Midstream) could be negatively affected in the long term by sustained downturns or sluggishness in the economy, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could impair our ability to meet our long-term goals. At the same time, we believe that the contractual fee-based nature of these assets should help to reduce this risk. Development projects over the past few years have also been exposed to increased cost pressures associated with a shortage availability of skilled labor and the pricing of materials, even though we have seen some of these pressures begin to decrease in certain geographic areas. Moreover, although it has become more difficult to obtain the authorizations required to develop or expand natural gas and NGL infrastructure, we remain confident that the incremental time and money required to pursue and complete market-driven facilities will deliver meaningful value to our unitholders. The regulatory environment, combined with the location of our assets relative to both high-demand markets and prolific shale basins, effectively provides a significant barrier to entry that other market participants may find difficult to overcome.
Inergy Midstream
Inergy Midstream is a predominantly fee-based, growth-oriented limited partnership that develops, acquires, owns and operates midstream energy assets. It owns and operates natural gas and NGL storage and transportation facilities and a salt production business located in the Northeast region of the United States. Inergy Midstream owns and operates four natural gas storage facilities that have an aggregate working gas storage capacity of 41.0 Bcf; natural gas pipeline facilities with 905 MMcf/d of transportation capacity; a 1.5 million barrel NGL storage facility; and US Salt, a leading solution mining and salt production company.
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Inergy Midstream's primary business objective is to increase the cash distributions that it pays to unitholders by growing its business through the development, acquisition and operation of additional midstream assets near production and demand centers. An integral part of its growth strategy is the continued development of Inergy Midstream's platform of interconnected natural gas assets in the Northeast that can be operated as an integrated storage and transportation hub. For example, because Inergy Midstream believes that storage and transportation customers value operating flexibility, it expects to increase the interconnectivity between its natural gas assets and third-party pipelines, thereby resulting in increased demand for its services. Its growth strategy is expected to reflect Inergy Midstream's desire to diversify its operations, in terms of both its geographic footprint and the type of midstream services it provides to customers.
Organic growth projects, including both expansions and greenfield development projects, have recently provided cost-effective options for Inergy Midstream to grow its infrastructure base. In general, purchasers of midstream infrastructure have paid relatively high prices (measured in terms of a multiple of EBITDA or another financial metric) to acquire midstream assets and operations in recent arms-length transactions. Although the prices paid for certain types of midstream assets are likely to remain robust for the foreseeable future, acquisitions will continue to permit Inergy Midstream to gain access to new markets (with respect to geographic footprint and product offerings) and develop the scale required to grow its business quickly and successfully. We therefore expect Inergy Midstream to grow its business in the near term through both organic growth projects and acquisitions.
Inergy Midstream's operations include (i) the storage and transportation of natural gas and NGLs, which are reported in its storage and transportation reporting segment, and (ii) US Salt's production and wholesale distribution of evaporated salt products, which are reported in its salt reporting segment. The cash flows from its storage and transportation operations are predominantly fee-based under one to ten year contracts with creditworthy counterparties and, therefore, are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations. The cash flows from its salt operations represent sales to creditworthy customers typically under contracts that are less than one year in duration, and these cash flows tend to be relatively stable and not subject to seasonal or cyclical variation due to the use of, and demand for salt products in everyday life.
The majority of Inergy Midstream's operating cash flows are generated by its natural gas storage operations. Its natural gas storage revenues are driven in large part by competition and demand for storage capacity and deliverability. Demand for storage in the Northeast is projected to continue to be strong, driven by a shortage in storage capacity and a higher than average annual growth in natural gas demand. This demand growth is primarily driven by the natural gas-fired electric generation sector and conversion from petroleum-based fuels. Due to the high percentage of its cash flows generated by its natural gas storage operations, Inergy Midstream has attempted to diversify its asset base recently by developing natural gas transportation assets and NGL storage assets. Its pending acquisition of Rangeland Energy also illustrates how Inergy Midstream expects to diversify its asset base through acquisitions.
Inergy Midstream's ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on its pipeline systems (basis spreads), economic conditions, and other factors. Its transportation facilities have benefited from, and Inergy Midstream expects its pipelines to continue to benefit from, the development of the Marcellus shale as a significant supply basin. As LDCs and other customers increasingly utilize short-haul transportation options to satisfy their transportation needs, the location of its transportation assets relative to the Marcellus shale will enable Inergy Midstream to realize additional benefits.
Inergy Midstream's long-term profitability will be influenced primarily by (i) successfully executing its existing development projects and continuing to develop new organic growth projects in its markets; (ii) pursuing strategic acquisitions from third parties, including us, to grow its business; (iii) contracting and re-contracting storage and transportation capacity with its customers; and (iv) managing increasingly difficult regulatory processes, particularly in permitting and approval proceedings at the federal and state levels.
We remain encouraged by Inergy Midstream's inventory of growth projects, such as the Watkins Glen NGL storage development project and the Commonwealth Pipeline project. These projects illustrate its diversification objectives, its desire to deploy capital prudently, its strong belief in the markets in which it operates, and its goal of integrating its assets when possible. Importantly, we also believe these projects demonstrate Inergy Midstream's commitment to its customers and their existing and forecast needs. In addition, many of its growth projects provide a basis for incremental growth, such as Inergy Midstream's ability to potentially expand the MARC I Pipeline through the installation of additional compression.
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How We Evaluate Our Operations
We evaluate our business performance on the basis of the following key measures:
• | cash available for distribution to our unitholders; |
• | distributions received from Inergy Midstream; |
• | revenues derived from our Tres Palacios natural gas storage facility; |
• | gross profit (excluding depreciation and amortization) derived from our NGL marketing, supply and logistics business; |
• | EBITDA and Adjusted EBITDA. |
We do not utilize depreciation, depletion and amortization expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.
Fiscal 2012 Acquisitions and Dispositions
In November 2011, we completed the acquisition of substantially all of the assets of Papco, LLC/South Jersey Terminal, LLC (“Papco”), located in Bridgeton, New Jersey. Papco provides transportation services to the NGL marketplace, mostly serving the East Coast, Midwest and Southeastern portions of the United States. South Jersey Terminal is a rail terminal facility with onsite product storage and truck loading operations. This acquisition provides our NGL business with a significant fleet of specialized transport vehicles and a strong presence in the Marcellus shale region, and allows us to increase our service offerings in the Eastern region of the United States.
In August 2012, we completed the acquisition of substantially all of the operating assets of Werner Transportation Services, Inc. (“Werner”), located in Gainesville, Georgia. Werner provides transportation services to the NGL marketplace primarily for customers east of the Mississippi River. This acquisition provides our NGL business with a strategic fleet of transport vehicles to help meet the increasing customer demand for hauling NGLs, notably in the Eastern region of the United States.
We acquired two retail propane businesses, one in January 2012 and one in February 2012, that were sold as part of our disposition of Inergy Propane to SPH in August 2012, as described below.
On August 1, 2012, we completed the disposition of our retail propane operations to SPH. We received approximately 14.2 million SPH common units with a market and book value of approximately $590 million, almost all of which we distributed to our unitholders in September 2012. SPH also exchanged approximately $1.19 billion of our outstanding senior notes for $1.0 billion of new SPH senior notes and paid cash directly to tendering note holders. In connection with the closing of this transaction, we entered into a support agreement with SPH pursuant to which we are obligated to provide contingent, residual support of approximately $497 million of aggregate principal amount of the 7½% senior unsecured notes due 2018 of SPH and Suburban Energy Finance Corp. (collectively, the “SPH Issuers”) or any permitted refinancing thereof. Under the support agreement, in the event the SPH Issuers fail to pay any principal amount of the supported debt when due, we will pay directly to, or to the SPH Issuers for the benefit of, the holders of the Supported Debt (“Holders”) an amount up to the principal amount of the supported debt that the SPH Issuers have failed to pay. We have no obligation to make a payment under the support agreement with respect to any accrued and unpaid interest or any redemption premium or other costs, fees, expenses, penalties, charges or other amounts of any kind whatsoever that shall be due to noteholders by the SPH Issuers, whether on or related to the supported debt or otherwise. The support agreement terminates on the earlier of the date the supported debt is extinguished or on the maturity date of supported debt or any permitted refinancing thereof.
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Recent Developments
On November 3, 2012, Inergy Midstream entered into an agreement to acquire Rangeland Energy for $425 million, subject to certain performance goals and working capital adjustments. Rangeland Energy owns and operates the COLT Hub, which is an integrated crude oil rail and storage terminal located in the heart of the Bakken and Three Forks shale oil-producing region. The Colt Hub primarily consists of 720,000 barrels of crude oil storage, two 8,700-foot unit train rail loading loops, an eight-bay truck unloading rack, and 21-mile bi-directional crude oil pipeline that connects the terminal to crude oil gathering systems and crude oil interstate pipelines. The COLT Hub is capable of moving more than 120,000 barrels of crude oil per day by rail. We expect Inergy Midstream to complete the Rangeland Energy acquisition in calendar 2012.
Inergy Midstream anticipates financing approximately $453 million of Rangeland Energy transaction costs and post-closing capital expenditures through a combination of debt and equity offerings. In particular, Inergy Midstream (i) entered into an agreement to sell $225 million through a private placement of common units to qualified institutional investors conditioned upon and closing contemporaneously with the closing of the Rangeland acquisition and (ii) Inergy Midstream expects to fund its remaining financing requirements through the sale of long-term senior notes or, if applicable, borrowings on an unsecured $225 million credit facility that Inergy Midstream has arranged to backstop its financing requirements. Inergy Midstream expects to complete these financing transactions prior to or contemporaneously with the closing of the Rangeland Energy acquisition.
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Results of Operations
Fiscal Year Ended September 30, 2012 Compared to Fiscal Year Ended September 30, 2011
The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2012 and 2011, respectively (in millions):
Year Ended September 30, | Change | |||||||||||||
2012 | 2011 | In Dollars | Percentage | |||||||||||
Revenue | $ | 2,006.8 | $ | 2,153.8 | $ | (147.0 | ) | (6.8 | )% | |||||
Cost of product sold | 1,396.2 | 1,476.0 | (79.8 | ) | (5.4 | ) | ||||||||
Gross profit (excluding depreciation and amortization) | 610.6 | 677.8 | (67.2 | ) | (9.9 | ) | ||||||||
Operating and administrative expenses | 300.8 | 323.3 | (22.5 | ) | (7.0 | ) | ||||||||
Depreciation and amortization | 169.6 | 191.8 | (22.2 | ) | (11.6 | ) | ||||||||
Loss on disposal of assets | 5.7 | 8.2 | (2.5 | ) | (30.5 | ) | ||||||||
Operating income | 134.5 | 154.5 | (20.0 | ) | (12.9 | ) | ||||||||
Interest expense, net | (83.6 | ) | (113.5 | ) | 29.9 | 26.3 | ||||||||
Gain on disposal of retail propane operations | 589.5 | — | 589.5 | * | ||||||||||
Loss on Suburban Propane Partners, L.P. units | (47.6 | ) | — | (47.6 | ) | * | ||||||||
Early extinguishment of debt | (26.6 | ) | (52.1 | ) | 25.5 | 48.9 | ||||||||
Other income | 1.5 | 1.2 | 0.3 | 25.0 | ||||||||||
Income (loss) before income taxes | 567.7 | (9.9 | ) | 577.6 | * | |||||||||
Provision for income taxes | 1.8 | 0.7 | 1.1 | 157.1 | ||||||||||
Net income (loss) | 565.9 | (10.6 | ) | 576.5 | * | |||||||||
Net (income) loss attributable to non-controlling partners | (11.0 | ) | 28.2 | (39.2 | ) | (139.0 | ) | |||||||
Net income attributable to partners | $ | 554.9 | $ | 17.6 | $ | 537.3 | * | |||||||
* | Not meaningful |
The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2012 and 2011, respectively (in millions):
Revenues | Gallons | |||||||||||||||||||||||||
Year Ended September 30, | Change | Year Ended September 30, | Change | |||||||||||||||||||||||
2012 | 2011 | In Dollars | Percent | 2012 | 2011 | In Units | Percent | |||||||||||||||||||
NGL Marketing, Supply and Logistics | ||||||||||||||||||||||||||
Retail | $ | 777.3 | $ | 1,050.9 | $ | (273.6 | ) | (26.0 | )% | 233.5 | 325.6 | (92.1 | ) | (28.3 | )% | |||||||||||
NGL Marketing | 618.9 | 562.9 | 56.0 | 9.9 | 504.3 | 395.5 | 108.8 | 27.5 | ||||||||||||||||||
L&L Transportation | 58.5 | 19.9 | 38.6 | 194.0 | — | — | — | — | ||||||||||||||||||
West Coast NGL | 313.7 | 309.7 | 4.0 | 1.3 | — | — | — | — | ||||||||||||||||||
Storage and Transportation | 238.4 | 210.4 | 28.0 | 13.3 | — | — | — | — | ||||||||||||||||||
Total | $ | 2,006.8 | $ | 2,153.8 | $ | (147.0 | ) | (6.8 | )% | 737.8 | 721.1 | 16.7 | 2.3 | % | ||||||||||||
Volume. During the year ended September 30, 2012, we sold 233.5 million retail gallons of propane, a decrease of 92.1 million gallons or 28.3% from the 325.6 million retail gallons sold during fiscal 2011. Gallons sold during the year ended September 30, 2012, decreased compared to the same prior year period primarily due to lower volumes sold at our existing locations of 93.0 million, partially offset by acquisition-related volume of 0.9 million. As indicated above, we sold our retail propane business to SPH effective August 1, 2012. As a result of this sale, gallons sold at existing locations reflected only ten months of operating activity during the year ended September 30, 2012 compared to twelve months for the prior year, which contributed an approximate 31.5 million gallon decline. For the remainder of the decline experienced during the year ended September 30, 2012, we believe that retail propane gallon sales were impacted by several ongoing factors, including lower
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demand arising from above average temperatures, customer conservation, high commodity prices and customers switching to other suppliers or energy sources. The weather during the year ended September 30, 2012 was approximately 21% warmer than the prior year period and approximately 20% warmer than normal in our areas of operations. These warmer temperatures had a significant negative impact on retail propane gallons sold during the year ended September 30, 2012. Additionally, although the average cost of propane has declined approximately 20% during the year ended September 30, 2012 compared to the prior year, the average wholesale cost of propane during our primary heating season from October to March 2012 increased approximately 2% compared to the same prior year period. We believe these higher costs during our primary heating season impacted customers' buying decisions and conservation trends, including customers seeking alternative sources of energy, such as electricity, wood burning and pellet burning stoves, since those sources can be more economical for the customer considering the higher cost of propane.
NGL marketing gallons delivered increased 108.8 million gallons, or 27.5%, to 504.3 million gallons in the year ended September 30, 2012, from 395.5 million gallons in the year ended September 30, 2011. This increase was driven primarily by (i) a 59.9 million gallon increase in Y-grade sales in the year ended September 30, 2012 as a result of increased production by the Caiman/Williams facility at Fort Beeler, West Virginia, noting that we marketed 100% of the production at this facility during the years ended September 30, 2012 and 2011; (ii) additional third party sales volumes to SPH after the close of the sale of the retail propane business to SPH, which accounted for an additional 21.7 million gallons in the year ended September 30, 2012 compared to the prior year period; and (iii) an increase in sales of 49.0 million gallons in the year ended September 30, 2012 specific to the Delaware City location, which was only operational for a portion of the prior year period. These increases were partially offset by lower volumes sold to existing customers primarily due to the warmer weather conditions in the year ended September 30, 2012 compared to the year ended September 30, 2011 as discussed above.
The total NGL gallons sold or processed by our West Coast NGL operations increased 93.3 million gallons, or 25.8%, to 455.6 million gallons during the year ended September 30, 2012, from 362.3 million gallons during the prior year period. The increase was primarily attributable to higher throughput volumes processed as a result of operational expansion of the facility in fiscal 2012, which accounted for 64.1 million gallons of the increase. An additional 29.8 million gallons of isomerization gallons were processed in the year ended September 30, 2012 due to favorable market conditions and changes in contractual obligations from the prior year.
Our Tres Palacios storage facility was approximately 53% and 69% contracted on a firm basis (83% and 80% contracted on a firm and interruptible basis) during the years ended September 30, 2012 and 2011, respectively. Additionally 100% of available capacity was sold at Inergy Midstream's Northeast natural gas facilities (Stagecoach, Steuben and Thomas Corners) on a firm basis, and the Bath NGL storage facility was approximately 100% contracted (for storage or forward sales). The Seneca Lake storage facility, which was acquired in July 2011, was approximately 72% and 59% contracted on a firm basis during the years ended September 30, 2012 and 2011, respectively.
Revenues. Revenues for the year ended September 30, 2012, were $2,006.8 million, a decrease of $147.0 million, or 6.8%, from $2,153.8 million during the same prior year period.
Revenues from retail sales were $777.3 million for the year ended September 30, 2012, compared to $1,050.9 million during the year ended September 30, 2011, a decrease of $273.6 million, or 26.0%. Retail propane revenues were $626.6 million in fiscal 2012, a decrease of $232.0 million compared to $858.6 million in fiscal 2011. This decrease was primarily due to a $245.2 million decline arising from lower retail propane volumes sold to existing customers as described above, partially offset by a $10.7 million increase due to a higher overall average selling price of propane and a $2.5 million increase resulting from acquisition-related retail propane sales. Approximately $81.2 million of the decrease attributable to lower volumes sold to existing customers resulted from the sale of our retail propane operations to SPH effective August 1, 2012. The overall average selling price of propane was higher than the same prior year period due to our ability to pass on to the customer at least a portion of the higher average wholesale cost of propane experienced during the primary heating season. Other retail sales, which primarily includes distillates, service, rental, and appliance sales, decreased $41.6 million to $150.7 million for the year ended September 30, 2012 from $192.3 million during the year ended September 30, 2011. Revenue from other retail sales declined $43.6 million, mostly as a result of lower distillate volumes sold at existing locations, of which approximately $21.3 million resulted from the sale of our retail propane operations to SPH. This decline was partially offset by a $2.0 million increase in other retail revenues as a result of acquisitions.
Revenues from NGL marketing sales were $618.9 million for the year ended September 30, 2012, an increase of $56.0 million, or 9.9%, from $562.9 million in the year ended September 30, 2011. The increase can be attributed to greater volumes sold to existing and new customers, which contributed $154.8 million to the increase, partially offset by a $98.8 million decline due to a lower average sales price for commodities sold.
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Revenues from L&L transportation sales were $58.5 million for the year ended September 30, 2012, an increase of $38.6 million or 194.0% from $19.9 million during the year ended September 30, 2011. This increase was primarily attributable to our acquisitions of the assets of Papco and Werner.
Revenues from our West Coast NGL operations were $313.7 million for the year ended September 30, 2012, an increase of $4.0 million or 1.3% from $309.7 million during the year ended September 30, 2011. West Coast facility revenues were $270.2 million for the year ended September 30, 2012 compared to $269.3 million in the prior year period, an increase of $0.9 million. This increase was primarily a result of increased throughput revenues as noted above, partially offset by lower commodity revenues resulting from lower commodity sales prices in fiscal 2012. West Coast propane revenues were $43.5 million for the year ended September 30, 2012 compared to $40.4 million for the prior year period, an increase of $3.1 million. These higher propane revenues were attributable to an increase of 8.3 million propane gallons sold at the West Coast facility for the year ended September 30, 2012, partially offset by lower sales price per gallon as a result of lower commodity costs.
Revenues from storage and pipeline transportation were $238.4 million for the year ended September 30, 2012, an increase of $28.0 million or 13.3% from $210.4 million during the year ended September 30, 2011. Revenues at our Tres Palacios facility increased $2.0 million primarily due to higher facility usage as a result of additional parking revenues. Inergy Midstream revenues increased $15.2 million primarily due to the placement into service of the North-South Facilities. Inergy Midstream's revenues also increased $8.4 million primarily due to additional demand for interruptible wheeling service as a result of customer demand to move gas to and from Inergy Midstream's interconnecting pipes primarily due to increasing natural gas development in Pennsylvania, and Inergy Midstream's acquisition of the Seneca Lake storage facility in July 2011 also increased revenue $6.5 million.
Cost of Product Sold. Cost of product sold for the year ended September 30, 2012, was $1,396.2 million, a decrease of $79.8 million, or 5.4%, from $1,476.0 million during the year ended September 30, 2011.
Retail cost of product sold was $438.8 million for the year ended September 30, 2012, a decrease of $156.1 million, or 26.2%, when compared to $594.9 million for the year ended September 30, 2011. Retail propane cost was $341.9 million in fiscal 2012, a decrease of $129.9 million compared to $471.8 million in fiscal 2011. This decline in retail propane cost of product sold was driven by a $134.4 million decrease resulting from lower volumes sold at existing locations, coupled with a $4.2 million decline due to a lower average per gallon cost of propane. These factors were partially offset by a $1.3 million increase due to acquisition-related sales, and a $7.4 million increase due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. The increase in non-cash charges on derivative contracts primarily relates to a $9.2 million non-cash gain recognized in the fourth quarter of 2012 related to certain derivative contracts entered into with SPH on the date of the close of the sale of our retail propane operations to SPH. These derivative contracts related to the procurement of propane at fixed prices to supply the propane necessary to satisfy fixed price sales contracts with retail customers that SPH acquired as part of their acquisition of our retail propane operations. We also have a related amount recorded as of September 30, 2012 as a loss in accumulated other comprehensive income related to derivative contracts that, prior to the sale of retail to SPH, were associated with our cash flow hedging activities related to fixed price sales to retail customers. The amount recorded in accumulated other comprehensive income as of September 30, 2012 is expected to be realized in earnings during the year ended September 30, 2013. Approximately $52.1 million of the decrease attributable to volumes sold at existing locations resulted from the sale of our retail propane operations to SPH effective August 1, 2012. Other retail cost of product sold was $96.9 million for the year ended September 30, 2012, compared to $123.1 million during the year ended September 30, 2011. This $26.2 million decrease was primarily due to a $27.8 million decline in the cost for distillates and other retail sales, partially offset by a $1.6 million increase from acquisitions. The decrease in the cost of product sold for distillates and other retail sales was driven by a $12.3 million decline due to the sale of our retail propane operations with the remainder of the decline due mostly to lower volumes of distillates sold at existing locations.
NGL marketing cost of product sold for the year ended September 30, 2012, was $590.2 million, an increase of $58.3 million, or 11.0%, from NGL marketing cost of product sold of $531.9 million for the year ended September 30, 2011. This increase was attributable to greater volumes sold to existing and new customers as noted above, which contributed $146.3 million to the increase, partially offset by an $88.0 million decrease due to a lower average purchase price as a result of lower commodity costs during the year ended September 30, 2012 compared to the prior year period.
L&L transportation cost of product sold was $34.1 million for the year ended September 30, 2012, an increase of $20.9 million or 158.3% from $13.2 million for the year ended September 30, 2011. This increase was primarily attributable to our acquisitions of the assets of Papco and Werner.
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Cost of product sold at our West Coast NGL operations was $281.1 million for the year ended September 30, 2012, a decrease of $1.1 million or 0.4% from $282.2 million for the year ended September 30, 2011. Cost of product sold for West Coast facility operations was $238.7 million for the year ended September 30, 2012 compared to $241.9 million for the prior year period, a decrease of $3.2 million. This decrease was primarily a result of lower average commodity prices and expected changes in types of NGLs sold, partially offset by higher throughput volumes processed. West Coast propane cost of product sold was $42.4 million for the year ended September 30, 2012 compared to $40.3 million for the prior year period, an increase of $2.1 million. This increase was attributable to increased volume sold as noted above, partially offset by lower commodity costs.
Storage and pipeline transportation cost of product sold was $52.0 million for the year ended September 30, 2012, a decrease of $1.8 million, or 3.3%, from $53.8 million for the year ended September 30, 2011. Storage and pipeline transportation cost of product sold at our Tres Palacios facility increased $2.5 million primarily due to an increase in cavern lease payments year over year. Inergy Midstream's storage and pipeline transportation cost of product sold decreased $3.4 million as a result of insurance reimbursements related to the Stagecoach central compressor loss, and also decreased $3.7 million related to the costs incurred in the prior period associated with the Stagecoach central compressor loss. Additionally, Inergy Midstream's storage and pipeline transportation costs decreased by $1.6 million due to a decrease in leased transportation capacity held on a non-affiliated interconnecting pipeline. The above decreases in Inergy Midstream's storage and pipeline transportation costs were partially offset by a $3.9 million increase in storage related costs incurred as a result of placing the North/South Facilities into service in December 2011.
Our retail and NGL marketing cost of product sold consists primarily of tangible products sold including all propane, distillates and other NGLs sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles approximated $63.9 million and $75.3 million for the years ended September 30, 2012 and 2011, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $57.7 million and $69.9 million for the years ended September 30, 2012 and 2011, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Our storage and pipeline transportation cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage and pipeline transportation services amounted to $70.5 million and $60.8 million for the year ended September 30, 2012 and 2011, respectively. Vehicle costs and wages for personnel directly involved in providing storage and pipeline transportation services amounted to $4.6 million and $3.5 million for the year ended September 30, 2012 and 2011, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Gross Profit (Excluding Depreciation and Amortization). Gross profit for the year ended September 30, 2012, was $610.6 million, a decrease of $67.2 million, or 9.9%, from $677.8 million during the year ended September 30, 2011.
Retail gross profit was $338.5 million for the year ended September 30, 2012, compared to $456.0 million for the year ended September 30, 2011, a decrease of $117.5 million, or 25.8%. Retail propane gross profit was $284.7 million in fiscal 2012, a decrease of $102.1 million compared to $386.8 million in fiscal 2011. This decrease was mostly due to a $110.8 million decline attributable to lower volumes sold at existing locations, coupled with a $7.4 million decline due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. Approximately $29.1 million of the decline from lower volumes sold at existing locations resulted from the sale of our retail propane operations to SPH effective August, 1, 2012. These factors were partially offset by an increase in retail gross profit of $14.9 million resulting from a higher cash margin per gallon and a $1.2 million increase associated with acquisitions. Other retail gross profit was $53.8 million for the year ended September 30, 2012, compared to $69.2 million for the year ended September 30, 2011. This $15.4 million decrease was due primarily to a decline in gross profit from distillate and other retail sales of $15.8 million, partially offset by an increase of $0.4 million arising from acquisition-related gross profit. Gross profit from distillate and other retail sales declined mostly due to lower volumes sold at our existing locations, approximately $9.0 million of which resulted from the sale of our retail propane operations.
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NGL marketing gross profit was $28.7 million for the year ended September 30, 2012, compared to $31.0 million for the year ended September 30, 2011, a decrease of $2.3 million, or 7.4%. This decrease resulted from lower margins on volumes sold to new and existing customers.
L&L transportation gross profit was $24.4 million for the year ended September 30, 2012, an increase of $17.7 million or 264.2% from $6.7 million during the year ended September 30, 2011. This increase was primarily attributable to our acquisitions of the assets of Papco and Werner.
Gross profit at our West Coast NGL operations was $32.6 million for the year ended September 30, 2012, an increase of $5.1 million or 18.5% from $27.5 million during the year ended September 30, 2011. This increase was primarily attributable to increased margins attained through increased throughput volumes and isomerization volumes during the period.
Storage and pipeline transportation gross profit was $186.4 million in the year ended September 30, 2012, compared to $156.6 million during the year ended September 30, 2011, an increase of $29.8 million, or 19.0%. This change is primarily related to the placement into service of the North/South Facilities and CNYOG's business interruption insurance reimbursement, which in total contributed $18.5 million to the increase. Inergy Midstream's acquisition of Seneca Lake in July 2011 resulted in an increase in gross profit of $6.3 million.
Operating and Administrative Expenses. Operating and administrative expenses were $300.8 million for the year ended September 30, 2012, compared to $323.3 million for the year ended September 30, 2011, a decrease of $22.5 million, or 7.0%. This change was primarily due to a $34.6 million decrease in operating expenses resulting from the sale of our retail propane operations to SPH effective August 1, 2012, an $8.6 million decrease in transaction expenses related to acquisitions in the prior fiscal year, and lower personnel and vehicle costs from existing operations of $7.4 million. Partially offsetting these decreases was an increase of $15.8 million due to acquisitions and a $12.1 million increase in long-term incentive and equity compensation expense as a result of greater amortization of existing awards and the net effect of a change in estimate of certain awards with performance conditions.
Depreciation and Amortization. Depreciation and amortization was $169.6 million for the year ended September 30, 2012, compared to $191.8 million during the year ended September 30, 2011. This $22.2 million, or 11.6%, decrease resulted primarily because we stopped depreciating and amortizing retail assets on May 1, 2012 as these assets were deemed held for sale and then ultimately sold on August 1, 2012. Partially offsetting this decrease was an increase related to acquisitions and the placing of Inergy Midstream assets into service during the year ended September 30, 2012.
Interest Expense. Interest expense was $83.6 million for the year ended September 30, 2012, compared to $113.5 million during the year ended September 30, 2011. This $29.9 million, or 26.3%, decrease was due primarily to a decline in average outstanding borrowings and a lower average interest rate incurred. Additionally, during the year ended September 30, 2012 and 2011, we capitalized $14.8 million and $16.2 million, respectively, of interest related to certain capital improvement projects in our storage and transportation segment as further described below in the “Liquidity and Sources of Capital” section.
Gain on Disposal of Retail Propane Operations. During the year ended September 30, 2012, we recorded a gain on the disposal of our retail propane operations of $589.5 million as further described above.
Loss on Suburban Propane Partners, L.P. Units. During the year ended September 30, 2012, we recorded an impairment loss of $47.6 million on the units of SPH we received from the sale of our retail propane operations. We accounted for our investment in SPH in accordance with the equity method and the impairment loss represents the drop in the SPH unit price during the 45 days we held these units. We distributed the SPH common units on September 14, 2012.
Early Extinguishment of Debt. During the year ended September 30, 2012, we paid in full the $300 million balance outstanding on our term loan facility, tendered substantially all the $95 million outstanding on our 2015 senior notes, tendered for $150 million of the $750 million outstanding on our 2021 senior notes, and reduced our revolving credit facility by $150 million. The loss associated with the above described transactions amounted to $26.6 million and was primarily related to the tender premiums and the write-off of previously capitalized charges associated with the original issuance of the respective debt. During the year ended September 30, 2011, we exercised our equity offerings redemption option in addition to a partial tender offer and redeemed 48% of our 2015 senior notes. Further, we tendered over 90% of both our 2014 and 2016 senior notes and the remaining amounts were redeemed in full. The loss associated with the above described transactions amounted to $52.1 million and was primarily related to the tender premium and the write-off of previously capitalized charges associated with the original issuance of the respective debt.
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Provision for Income Taxes. The provision for income taxes for the year ended September 30, 2012, was $1.8 million compared to $0.7 million for the year ended September 30, 2011. The provision for income taxes for the year ended September 30, 2012, was composed of $1.4 million of current income tax expense and $0.4 million of deferred income tax expense.
Net Income (Loss). Net income was $565.9 million for the year ended September 30, 2012, compared to a net loss of $(10.6) million for the year ended September 30, 2011. The $576.5 million increase in net income was primarily attributable to the $589.5 million gain on disposal of retail propane operations, a $25.5 million decrease in charges related to the early extinguishment of debt, a $29.9 million decrease in interest expense and the lower operating and administrative expenses and depreciation and amortization primarily resulting from the contribution of our retail propane operations to SPH on August 1, 2012. Partially offsetting these increases to net income was the $(47.6) million loss on SPH units and lower gross profit as discussed above.
Net (Income) Loss Attributable to Non-Controlling Partners. The earnings of non-controlling partners of $11.0 million for the year ended September 30, 2012, solely relates to the 25% minority interest in Inergy Midstream's net income. Inergy Midstream's IPO occurred in December 2011. The net loss attributable to non-controlling interest for the year ended September 30, 2011 of $28.2 million was related entirely to earnings of non-controlling partners prior to the November 2010 merger of Inergy and Holdings. The merger eliminated this group of non-controlling partners.
EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2012 and 2011, respectively (in millions):
Year Ended September 30, | |||||||
2012 | 2011 | ||||||
EBITDA: | |||||||
Net income (loss) | $ | 565.9 | $ | (10.6 | ) | ||
Interest expense, net | 83.6 | 113.5 | |||||
Early extinguishment of debt | 26.6 | 52.1 | |||||
Provision for income taxes | 1.8 | 0.7 | |||||
Depreciation and amortization | 169.6 | 191.8 | |||||
EBITDA | $ | 847.5 | $ | 347.5 | |||
Non-cash (gain) loss on derivative contracts | (8.6 | ) | 1.2 | ||||
Long-term incentive and equity compensation expense | 17.9 | 5.8 | |||||
Loss on disposal of assets | 5.7 | 8.2 | |||||
Gain on disposal of retail propane operations | (589.5 | ) | — | ||||
Loss on Suburban Propane Partners, L.P. units | 47.6 | — | |||||
Transaction costs | 0.9 | 9.5 | |||||
Adjusted EBITDA | $ | 321.5 | $ | 372.2 | |||
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Year Ended September 30, | |||||||
2012 | 2011 | ||||||
EBITDA: | |||||||
Net cash provided by operating activities | $ | 239.0 | $ | 114.4 | |||
Net changes in working capital balances | (9.4 | ) | 104.1 | ||||
Non-cash early extinguishment of debt | (10.0 | ) | (12.7 | ) | |||
Provision for doubtful accounts | (2.1 | ) | (3.7 | ) | |||
Amortization of deferred financing costs, swap premium and net bond discount | (4.9 | ) | (7.4 | ) | |||
Unit-based compensation charges | (12.9 | ) | (5.8 | ) | |||
Loss on disposal of assets | (5.7 | ) | (8.2 | ) | |||
Gain on disposal of retail propane operations | 589.5 | — | |||||
Loss on Suburban Propane Partners, L.P. units | (47.6 | ) | — | ||||
Deferred income tax | (0.4 | ) | 0.5 | ||||
Interest expense, net | 83.6 | 113.5 | |||||
Early extinguishment of debt | 26.6 | 52.1 | |||||
Provision for income taxes | 1.8 | 0.7 | |||||
EBITDA | $ | 847.5 | $ | 347.5 | |||
Non-cash (gain) loss on derivative contracts | (8.6 | ) | 1.2 | ||||
Long-term incentive and equity compensation expense | 17.9 | 5.8 | |||||
Loss on disposal of assets | 5.7 | 8.2 | |||||
Gain on disposal of retail propane operations | (589.5 | ) | — | ||||
Loss on Suburban Propane Partners, L.P. units | 47.6 | — | |||||
Transaction costs | 0.9 | 9.5 | |||||
Adjusted EBITDA | $ | 321.5 | $ | 372.2 | |||
EBITDA is defined as income before income taxes, plus net interest expense, early extinguishment of debt and depreciation and amortization expense. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, long-term incentive and equity compensation expenses, the gain or loss on the disposal of assets, the gain on disposal of retail propane operations, the loss on SPH units, and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
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Fiscal Year Ended September 30, 2011 Compared to Fiscal Year Ended September 30, 2010
The following table summarizes the consolidated income statement components for the fiscal years ended September 30, 2011 and 2010, respectively (in millions):
Year Ended September 30, | Change | |||||||||||||
2011 | 2010 | In Dollars | Percentage | |||||||||||
Revenue | $ | 2,153.8 | $ | 1,786.0 | $ | 367.8 | 20.6 | % | ||||||
Cost of product sold | 1,476.0 | 1,165.9 | 310.1 | 26.6 | ||||||||||
Gross profit (excluding depreciation and amortization) | 677.8 | 620.1 | 57.7 | 9.3 | ||||||||||
Operating and administrative expenses | 323.3 | 310.7 | 12.6 | 4.1 | ||||||||||
Depreciation and amortization | 191.8 | 161.8 | 30.0 | 18.5 | ||||||||||
Loss on disposal of assets | 8.2 | 11.5 | (3.3 | ) | (28.7 | ) | ||||||||
Operating income | 154.5 | 136.1 | 18.4 | 13.5 | ||||||||||
Interest expense, net | (113.5 | ) | (91.5 | ) | (22.0 | ) | (24.0 | ) | ||||||
Early extinguishment of debt | (52.1 | ) | — | (52.1 | ) | * | ||||||||
Other income | 1.2 | 2.0 | (0.8 | ) | (40.0 | ) | ||||||||
Income (loss) before income taxes | (9.9 | ) | 46.6 | (56.5 | ) | (121.2 | ) | |||||||
Provision for income taxes | 0.7 | 0.2 | 0.5 | 250.0 | ||||||||||
Net income (loss) | (10.6 | ) | 46.4 | (57.0 | ) | (122.8 | ) | |||||||
Net loss attributable to non-controlling partners | 28.2 | 15.4 | 12.8 | 83.1 | ||||||||||
Net income attributable to partners | $ | 17.6 | $ | 61.8 | $ | (44.2 | ) | (71.5 | )% | |||||
* | not meaningful |
The following table summarizes revenues, including associated volume of gallons sold, for the years ended September 30, 2011 and 2010, respectively (in millions):
Revenues | Gallons | |||||||||||||||||||||||||
Year Ended September 30, | Change | Year Ended September 30, | Change | |||||||||||||||||||||||
2011 | 2010 | In Dollars | Percent | 2011 | 2010 | In Units | Percent | |||||||||||||||||||
Propane | ||||||||||||||||||||||||||
Retail propane | $ | 858.6 | $ | 796.5 | $ | 62.1 | 7.8 | % | 325.6 | 340.2 | (14.6 | ) | (4.3 | )% | ||||||||||||
Wholesale propane | 603.3 | 475.9 | 127.4 | 26.8 | 422.8 | 415.3 | 7.5 | 1.8 | ||||||||||||||||||
Other retail | 212.2 | 194.5 | 17.7 | 9.1 | — | — | — | — | ||||||||||||||||||
Midstream | 479.7 | 319.1 | 160.6 | 50.3 | — | — | — | — | ||||||||||||||||||
Total | $ | 2,153.8 | $ | 1,786.0 | $ | 367.8 | 20.6 | % | 748.4 | 755.5 | (7.1 | ) | (0.9 | )% | ||||||||||||
Volume. During the year ended September 30, 2011, we sold 325.6 million retail gallons of propane, a decrease of 14.6 million gallons or 4.3% from the 340.2 million retail gallons sold during fiscal 2010. Gallons sold during the year ended September 30, 2011, decreased as compared to the same prior year period as a result of lower volumes sold at our existing locations of 42.4 million, partially offset by an increase arising from acquisition volume of 27.8 million gallons. The primary causes of the declining volumes at existing locations were (i) a decline in low margin agricultural propane sold due to lesser crop drying demand in the current year period compared to prior year, (ii) continued customer conservation, which we believe has resulted from the continued impact of the overall weak United States economic environment and higher propane costs, which have been at record high prices the past several years and which have increased during the fiscal period ended September 30, 2011, (iii) volume declines from net customer losses primarily as a result of higher selling prices, and (iv) warmer weather in our South and Southeast areas of operations. The average wholesale cost of propane has increased approximately 27% during the year ended September 30, 2011, compared to the same prior year period, continuing to impact customer buying decisions and conservation trends. Although certain of our areas of operations (South and Southeast) were warmer during the fiscal period ended September 30, 2011, compared to the same prior year period, on a consolidated retail basis, weather during the current year ended was approximately 2% colder than the prior year period and approximately 1.3% colder than normal.
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Wholesale gallons delivered increased 7.5 million gallons, or 1.8%, to 422.8 million gallons in the year ended September 30, 2011, from 415.3 million gallons in the year ended September 30, 2010. The increase was due primarily to higher demand and volumes sold to existing and new customers.
The total NGL gallons sold or processed by our West Coast NGL operations decreased 14.9 million gallons, or 4.3%, to 335.0 million gallons during the year ended September 30, 2011, from 349.9 million gallons during fiscal 2010. This decrease was primarily attributable to decreased volume processed, partially offset by increased volume of NGL products sold. Both of the aforementioned changes were primarily due to local market conditions.
During the year ended September 30, 2011, our Tres Palacios storage facility, which was acquired in October 2010, was approximately 69% contracted on a firm basis (80% contracted on a firm and interruptible basis). Additionally during the years ended September 30, 2011 and 2010, 100% of available capacity was sold at Inergy Midstream's Northeast natural gas facilities (Stagecoach, Steuben and Thomas Corners) on a firm basis, and the Bath NGL storage facility was approximately 100% contracted (for storage or forward sales). The Seneca Lake storage facility, which was acquired in July 2011, was approximately 59% contracted on a firm basis during the year ended September 30, 2011.
Revenues. Revenues for the year ended September 30, 2011, were $2,153.8 million, an increase of $367.8 million, or 20.6%, from $1,786.0 million during fiscal 2010.
Revenues from retail propane sales were $858.6 million for the year ended September 30, 2011, compared to $796.5 million during fiscal 2010. This $62.1 million, or 7.8%, increase was due to a higher overall average selling price of propane and acquisition-related sales, which resulted in higher retail propane revenues of $91.5 million and $69.7 million, respectively. The overall average selling price of propane increased due to an increase in the wholesale cost of propane. These factors were partially offset by a $99.1 million revenue decline arising from a decrease in gallons sold to existing customers as described above.
Revenues from wholesale propane sales were $603.3 million in the year ended September 30, 2011, an increase of $127.4 million or 26.8%, from $475.9 million in the year ended September 30, 2010. This increase was driven primarily by a higher average selling price, which contributed $118.7 million to the increase and higher volumes sold, which contributed $8.7 million to the increase.
Revenues from other retail sales, which primarily includes distillates, service, rental, appliance sales and transportation services, were $212.2 million for the year ended September 30, 2011, an increase of $17.7 million, or 9.1%, from $194.5 million during fiscal 2010. Revenue from other retail sales increased as a result of higher distillate revenues of $16.7 million and an increase related to acquisitions of $3.5 million, partially offset by a $2.5 million decline in appliance, parts and other retail revenues. Distillate revenues from existing locations increased as a result of a higher comparable average selling price of distillates due to a higher wholesale cost, partially offset by lower volume sold.
Revenues from storage, fractionation and other midstream activities were $479.7 million for the year ended September 30, 2011, an increase of $160.6 million or 50.3% from $319.1 million during fiscal 2010. Revenues from our West Coast NGL operations increased $96.8 million primarily as a result of increased higher average selling prices of NGLs, along with increased NGL products sold. The acquisition of our Tres Palacios gas storage facility and the commencement of the Thomas Corners gas storage contracts in April 2010 increased revenues by $46.0 million and $8.1 million, respectively. Additionally revenues at the Stagecoach facility have increased $7.7 million due to interruptible wheeling service as a result of customer demand to move gas to/from interconnecting pipes primarily due to natural gas development in Pennsylvania.
Cost of Product Sold. Cost of product sold for the year ended September 30, 2011, was $1,476.0 million, an increase of $310.1 million, or 26.6%, from $1,165.9 million during fiscal 2010.
Retail propane cost of product sold was $471.8 million for the year ended September 30, 2011, an increase of $58.1 million, or 14.0%, when compared to $413.7 million for fiscal 2010. This higher retail cost of product sold was driven by a $68.2 million increase arising from a higher average per gallon cost of propane and a $39.3 million increase associated with acquisition-related sales. Also contributing to a higher cost of product sold was a $2.2 million increase due to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. These factors were partially offset by a $51.6 million decline in cost of product sold resulting from lower volume sales at our existing locations as discussed above.
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Wholesale propane cost of product sold in the year ended September 30, 2011, was $572.2 million, an increase of $123.0 million or 27.4%, from wholesale cost of product sold of $449.2 million in the year ended September 30, 2010. This increase resulted from the higher average purchase price of propane, which contributed $114.8 million to the increase and greater volumes sold, which contributed $8.2 million.
Other retail cost of product sold was $136.3 million for the year ended September 30, 2011, compared to $113.1 million during fiscal 2010. This $23.2 million, or 20.5%, increase was primarily as a result of a $20.4 million increase in the cost for distillates, a $1.1 million increase in the cost of product sold associated with acquisition-related sales and a $1.7 million increase in the cost of other retail sales. The increase in the cost of product sold for distillates was driven by a $25.3 million increase due to a higher overall commodity cost, partially offset by a $4.9 million decline due to lower volumes sold at existing locations.
Storage, fractionation and other midstream cost of product sold was $295.7 million for the year ended September 30, 2011, an increase of $105.8 million, or 55.7%, from $189.9 million during fiscal 2010. Costs from our West Coast NGL operations were $94.1 million higher as a result of higher average commodity prices for NGLs, along with increased NGL products sold. Additionally, the acquisition of our Tres Palacios gas storage facility resulted in a $10.0 million increase over the prior year.
Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane, distillates and other NGLs sold and all propane-related appliances sold. Other costs incurred in conjunction with the distribution of these products are included in operating and administrative expenses and consist primarily of wages to delivery personnel, delivery vehicle costs consisting of fuel costs, repair and maintenance and lease expense. Costs associated with delivery vehicles approximated $74.0 million and $67.0 million for the year ended September 30, 2011 and 2010, respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $29.4 million and $32.8 million for the year ended September 30, 2011 and 2010, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Our storage, fractionation and other midstream cost of product sold consists primarily of commodity and transportation costs. Other costs incurred in conjunction with these services are included in operating and administrative expense and depreciation and amortization expense and consist primarily of depreciation, vehicle costs consisting of fuel costs and repair and maintenance and wages. Depreciation expense for storage, fractionation and other midstream amounted to $101.4 million and $73.6 million for the year ended September 30, 2011 and 2010, respectively. Vehicle costs and wages for personnel directly involved in providing midstream services amounted to $4.7 million and $2.9 million for the year ended September 30, 2011 and 2010, respectively. Since we include these costs in our operating and administrative expense and depreciation and amortization expense rather than in cost of product sold, our results may not be comparable to other entities in our lines of business if they include these costs in cost of product sold.
Gross Profit (Excluding Depreciation and Amortization). Gross profit for the year ended September 30, 2011, was $677.8 million, an increase of $57.7 million, or 9.3%, from $620.1 million during fiscal 2010.
Retail propane gross profit was $386.8 million for the year ended September 30, 2011, compared to $382.8 million in fiscal 2010. This $4.0 million, or 1.0%, increase was primarily driven by acquisitions and a higher cash margin per gallon, which contributed increases of $30.4 million and $23.3 million respectively. The higher cash margin per gallon was primarily due to the average selling price increasing at a greater rate than the increased cost of propane including the impact of lesser agricultural gallons sold, which generally have a lower margin. These factors were partially offset by a gross profit decline of $47.5 million attributable to lower retail gallon sales at existing locations as discussed above and a $2.2 million decline related to changes in non-cash charges on derivative contracts associated with retail propane fixed price sales contracts as discussed above.
Wholesale propane gross profit was $31.1 million in the year ended September 30, 2011, compared to $26.7 million in the year ended September 30, 2010, an increase of $4.4 million, or 16.5%. This increase resulted from higher margins obtained which contributed $3.9 million to the increase and greater volumes sold to new and existing customers, which contributed $0.5 million.
Other retail gross profit was $75.9 million for the year ended September 30, 2011, compared to $81.4 million for fiscal 2010. This $5.5 million, or 6.8%, decrease was primarily due to a $3.7 million decline in gross profit from distillates and a $4.2 million decline in other retail gross profit, partially offset by a $2.4 million increase in gross profit related to acquisitions.
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Storage, fractionation and other midstream gross profit was $184.0 million in the year ended September 30, 2011, compared to $129.2 million in fiscal 2010, an increase of $54.8 million, or 42.4%. This increase was partially attributable to the gas storage acquisition of Tres Palacios, which contributed $36.0 million to the higher gross profit. The completion of the Thomas Corners gas storage facility in November 2009, and the relating storage contracts coming online in April 2010, also increased gross profit by approximately $7.4 million. Additionally an increase in interruptible wheeling revenues at the Stagecoach facility increased gross profit by approximately $6.0 million. Gross profit from our West Coast NGL operations was $2.7 million higher as a result of higher average margins, along with increased NGLs sold to existing and new customers.
Operating and Administrative Expenses. Operating and administrative expenses were $323.3 million for the year ended September 30, 2011, compared to $310.7 million in fiscal 2010, an increase of $12.6 million or 4.1%. Included in the 2011 operating expenses were $9.5 million of transaction costs, primarily financing commitment expenses for the Tres Palacios acquisition, directly related to closing acquisitions during the period. The transaction costs for the same period of the prior year were $3.5 million. In addition, operating expenses increased $22.5 million due to the operations of acquisitions, partially offset by lower personnel costs from existing operations, which decreased $19.3 million, and lower insurance and other operating expenses.
Depreciation and Amortization. Depreciation and amortization was $191.8 million for the year ended September 30, 2011, compared to $161.8 million during fiscal 2010. This $30.0 million, or 18.5%, increase resulted primarily from acquisitions.
Loss on Disposal of Assets. Loss on disposal of assets decreased $3.3 million, or 28.7%, to $8.2 million in fiscal 2011 compared to $11.5 million in fiscal 2010. The losses recognized in fiscal 2011 and 2010 include losses of $11.1 million and $9.7 million, respectively, related to assets held for sale, which have been written down to their estimated selling price. In addition, we had gains in fiscal 2011 of $2.9 million and other losses in fiscal 2010 of $1.8 million. These assets, both those sold and those held for sale, consist primarily of vehicles, tanks and real estate deemed to be excess, redundant or underperforming assets. In fiscal 2011 and 2010, these assets were identified primarily as a result of losses due to disconnecting customer installations of less profitable accounts due to low margins, poor payment history or low volume usage and customers who have chosen to switch suppliers.
Interest Expense. Interest expense was $113.5 million for the year ended September 30, 2011, compared to $91.5 million during fiscal 2010. This $22.0 million, or 24.0%, increase was due primarily to an increase in the average outstanding borrowings during the period due to acquisitions, partially offset by a decrease in the average interest rate incurred on those borrowings. Additionally, during the year ended September 30, 2011 and 2010, we capitalized $16.2 million and $6.4 million, respectively, of interest related to certain capital improvement projects in our storage and transportation segment as further described below in the “Liquidity and Sources of Capital” section.
Early Extinguishment of Debt. During the year ended September 30, 2011, we exercised our equity offerings redemption option in addition to a partial tender offer and redeemed 48% of our 2015 senior notes. Further, we tendered over 90% of both our 2014 and 2016 senior notes and the remaining amounts were redeemed in full. The loss associated with the above described transactions amounted to $52.1 million and was primarily related to the tender premium and the write-off of previously capitalized charges associated with the original issuance of the respective debt.
Provision for Income Taxes. The provision for income taxes for the year ended September 30, 2011, was $0.7 million compared to $0.2 million in fiscal 2010. The provision for income taxes for the year ended September 30, 2011, was composed of $1.2 million of current income tax expense partially offset by a $0.5 million deferred income tax benefit. The provision for income taxes for the year ended September 30, 2010, was composed of $0.5 million of current income tax expense partially offset by a $0.3 million deferred income tax benefit.
Net Income (Loss). Net loss was $(10.6) million for the year ended September 30, 2011, compared to net income of $46.4 million for fiscal 2010. The $57.0 million, or 122.8%, decrease in net income was primarily attributable to the charge for the early extinguishment of debt, increased depreciation and amortization, operating and administrative expenses and interest expense in the 2011 period, partially offset by higher gross profit.
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EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal years ended September 30, 2011 and 2010, respectively (in millions):
Year Ended September 30, | |||||||
2011 | 2010 | ||||||
EBITDA: | |||||||
Net income (loss) | $ | (10.6 | ) | $ | 46.4 | ||
Interest expense, net | 113.5 | 91.5 | |||||
Early extinguishment of debt | 52.1 | — | |||||
Provision for income taxes | 0.7 | 0.2 | |||||
Depreciation and amortization | 191.8 | 161.8 | |||||
EBITDA | $ | 347.5 | $ | 299.9 | |||
Non-cash (gain) loss on derivative contracts | 1.2 | (1.0 | ) | ||||
Long-term incentive and equity compensation expense | 5.8 | 10.9 | |||||
Loss on disposal of assets | 8.2 | 11.5 | |||||
Transaction costs | 9.5 | 3.5 | |||||
Adjusted EBITDA | $ | 372.2 | $ | 324.8 | |||
Year Ended September 30, | |||||||
2011 | 2010 | ||||||
EBITDA: | |||||||
Net cash provided by operating activities | $ | 114.4 | $ | 173.6 | |||
Net changes in working capital balances | 104.1 | 60.7 | |||||
Non-cash early extinguishment of debt | (12.7 | ) | — | ||||
Provision for doubtful accounts | (3.7 | ) | (2.8 | ) | |||
Amortization of deferred financing costs, swap premium and net bond discount | (7.4 | ) | (7.3 | ) | |||
Long-term incentive and equity compensation expense | (5.8 | ) | (4.8 | ) | |||
Loss on disposal of assets | (8.2 | ) | (11.5 | ) | |||
Deferred income tax | 0.5 | 0.3 | |||||
Interest expense, net | 113.5 | 91.5 | |||||
Early extinguishment of debt | 52.1 | — | |||||
Provision for income taxes | 0.7 | 0.2 | |||||
EBITDA | $ | 347.5 | $ | 299.9 | |||
Non-cash (gain) loss on derivative contracts | 1.2 | (1.0 | ) | ||||
Long-term incentive and equity compensation expense | 5.8 | 10.9 | |||||
Loss on disposal of assets | 8.2 | 11.5 | |||||
Transaction costs | 9.5 | 3.5 | |||||
Adjusted EBITDA | $ | 372.2 | $ | 324.8 | |||
EBITDA is defined as income before income taxes, plus net interest expense, early extinguishment of debt and depreciation and amortization expense. As indicated in the table, Adjusted EBITDA represents EBITDA excluding the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, long-term incentive and equity compensation expenses, the gain or loss on the disposal of assets and transaction costs. Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
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Liquidity and Sources of Capital
We are a partnership holding company that derives all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated by operating activities, credit facilities (including our Credit Agreement), debt issuances, and sales of our common units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital expenditures. We use cash generated by our operating subsidiaries and, if applicable, borrowings under our Credit Facility to service our outstanding indebtedness, fund growth capital expenditures, and make distributions to unitholders. We do not guarantee indebtedness of, or have similar commitments to, Inergy Midstream or its wholly-owned subsidiaries.
Inergy Midstream uses cash generated by operating activities and credit facilities (including its $600 million credit facility) to fund its operating activities and maintenance capital expenditures. It uses cash generated by its operating subsidiaries and, if applicable, borrowings under its credit facility to service its outstanding indebtedness, fund growth capital expenditures, and make distributions to unitholders. Inergy Midstream does not guarantee indebtedness of, or have similar commitments to, us or our wholly-owned subsidiaries.
Capital Resource Activities
On March 16, 2011, our shelf registration statement (File No. 333-172312) was declared effective by the SEC for the periodic sale of up to $1.5 billion of common units, partnership securities and debt securities, or any combination thereof. On June 6, 2011, we issued 9,000,000 common units in a public offering. We used the net proceeds from this offering to repay borrowings under our revolving general partnership and working capital credit facilities, to fund ongoing expansion projects in our midstream business and for general partnership purposes. We have approximately $1.2 billion remaining under this shelf registration statement.
Cash Flows and Contractual Obligations
Fiscal Year Ended September 30, 2012 Compared to Fiscal Year Ended September 30, 2011
Net operating cash inflows were $239.0 million and $114.4 million for the fiscal years ended September 30, 2012 and 2011, respectively. The $124.6 million increase in operating cash flows was primarily attributable to an approximate $117.1 million impact from certain inventory contracts entered into during the prior year period that were for the delivery of NGLs during the year ended September 30, 2012. The cash received related to the delivery of this product was received during the year ended September 30, 2012 and the inventory to satisfy these contracts was purchased during the prior year period. Also contributing to the increase in operating cash flows was a $22.8 million decrease in cash cost of early extinguishment of debt and a $34.6 million decline in cash operating expenses. Partially offsetting these increases in operating cash flows was a $67.2 million decline in gross profit and a $17.5 million increase in cash paid for interest. The remainder of the increase in operating cash flows was attributable to other changes in working capital items, including the timing of payments on payables and the collection of receivables.
Net investing cash outflows were $350.6 million and $390.6 million for the fiscal years ended September 30, 2012 and 2011, respectively. Net cash outflows were primarily impacted by a $792.0 million decrease in cash outlays related to acquisitions, partially offset by a $588.0 million investment in escrow account that was utilized in fiscal 2011 to fund the Tres Palacios acquisition, total payments of $58.1 million associated with the sale of our retail propane operations, a $17.8 million decrease in proceeds from the sale of assets, and an $88.1 million increase in capital expenditures. The increase in capital expenditures is primarily related to the previously discussed midstream growth projects.
Net financing cash inflows were $100.1 million and $143.3 million for the fiscal years ended September 30, 2012 and 2011, respectively. The net change was primarily impacted by a $48.6 million decrease in net borrowings.
Fiscal Year Ended September 30, 2011 Compared to Fiscal Year Ended September 30, 2010
Net operating cash inflows were $114.4 million and $173.6 million for the fiscal years ended September 30, 2011 and 2010, respectively. The $59.2 million decrease in operating cash flows was primarily attributable to the $39.4 million cash cost of our early extinguishment of debt. Also contributing to the decrease in operating cash flows was an increase in expenditures for inventory due primarily to an increase in commodity prices.
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Net investing cash outflows were $390.6 million and $926.4 million for the fiscal years ended September 30, 2011 and 2010, respectively. Net cash outflows were primarily impacted by a $588.0 million investment in an escrow account that was utilized to fund the Tres Palacios acquisition and a $19.6 million increase in proceeds from the sale of assets. These investing cash inflows were partially offset by a $571.5 million increase in cash outlays related to acquisitions and an $88.3 million increase in capital expenditures. The increase in acquisitions was primarily related to the acquisition of Tres Palacios, and the increase in capital expenditures was primarily related to certain midstream growth projects.
Net financing cash inflows were $143.3 million and $885.5 million for the fiscal years ended September 30, 2011 and 2010, respectively. The net change was primarily impacted by a $404.8 million decrease in proceeds related to the issuance of long-term debt, net of payments on long-term debt, a $68.8 million increase in the total distributions paid, a $291.5 million decrease in proceeds from the issuance of common units and a $3.8 million decrease in proceeds from common unit options exercised, partially offset by a $3.1 million decrease in payments for deferred financing costs and a $5.9 million increase in proceeds from swap settlement.
At September 30, 2012 and 2011, we had goodwill of $165.8 million and $162.0 million, respectively, representing 8% and 5% of total assets in each year, respectively. This goodwill is attributable to our acquisitions.
At September 30, 2012, we were in compliance with all debt covenants to our credit facilities.
The following table summarizes our contractual obligations as of September 30, 2012 (in millions):
Total | Less than 1 year | 1-3 years | 4-5 years | After 5 years | |||||||||||||||
Aggregate amount of principal and interest to be paid on the outstanding long-term debt(a) | $ | 821.4 | $ | 22.5 | $ | 39.0 | $ | 745.6 | $ | 14.3 | |||||||||
Future minimum lease payments under noncancelable operating leases | 405.6 | 15.5 | 30.7 | 35.7 | 323.7 | ||||||||||||||
Fixed price purchase commitments(c) | 351.2 | 346.7 | 4.5 | — | — | ||||||||||||||
Standby letters of credit | 56.3 | 55.3 | 1.0 | — | — | ||||||||||||||
Purchase commitments of identified growth projects(b) | 22.6 | 22.6 | — | — | — | ||||||||||||||
Total contractual obligations | $ | 1,657.1 | $ | 462.6 | $ | 75.2 | $ | 781.3 | $ | 338.0 | |||||||||
(a) | $503.2 million of our long-term debt, including interest rate swaps, is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 1.97% and 5.00% at September 30, 2012. These rates have been applied for each period presented in the table. |
(b) | Identified growth projects primarily related to the Watkins Glen NGL development project and the MARC I Pipeline. |
(c) | Fixed price purchase commitments are volumetrically offset by third party fixed price sale contracts. |
We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. While global financial markets and economic conditions have been disrupted and volatile in the past, the conditions have improved more recently. However, we give no assurance that we can raise additional capital to meet these needs. We have identified capital expansion project opportunities in our storage and transportation operations. As of September 30, 2012, we have firm purchase commitments totaling approximately $0.4 million related to certain of our growth projects, and Inergy Midstream has firm purchase commitments totaling approximately $22.2 million related to certain of its growth projects. Additional commitments or expenditures, if any, we may make toward any one or more of these projects are at our discretion. Any discontinuation of the construction of these projects will likely result in less future cash flow and earnings.
Description of Credit Facilities
Inergy, L.P.
On November 24, 2009, we entered into a secured credit facility (“Credit Agreement”) which, at the time, provided borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility was to mature on November 22, 2013. Borrowings under these secured facilities are available for working capital needs, future acquisitions, capital expenditures and other general partnership purposes, including the refinancing of existing indebtedness under the former credit facility.
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On February 2, 2011, we amended and restated the Credit Agreement to add a $300 million term loan facility (the “Term Loan Facility”). The term loan was repaid in full in December 2011 as discussed below.
On July 28, 2011, we further amended our Credit Agreement to (i) raise the aggregate revolving commitment from $525 million to $700 million (“Revolving Loan Facility”) with that amount existing as a singular tranche, (ii) reduce the applicable rate on revolving loans and commitment fees, (iii) modify and refresh certain covenants and covenant baskets, and (iv) extend the maturity date from November 22, 2013 to July 28, 2016.
On April 13, 2012, we further amended our Credit Agreement. This amendment, among other things, (i) permitted us to sell up to 5,000,000 of the Inergy Midstream common units we own, (ii) permitted us to sell US Salt, (iii) decreased the aggregate revolving commitment and general partnership commitment from $700 million to $550 million, and (iv) adjusted several of the financial covenants.
On July 26, 2012, we further amended our Credit Agreement in order to (i) permit us to enter into a series of transactions as described in the Contribution Agreement dated as of April 25, 2012 among us and SPH, (ii) permit us to repurchase, repay or redeem all or any portion of the senior notes that remain outstanding after the closing of the Contribution Agreement, (iii) modify certain negative and financial covenants under the Credit Agreement, and (iv) allow us to redeem, buy back or otherwise acquire up to $100 million of our common units on or prior to March 31, 2013. This amendment did not become effective until the contribution of our retail propane assets to SPH closed on August 1, 2012. In conjunction with the close of this transaction, $1,187.0 million of our senior notes were exchanged for SPH senior notes and cash paid directly to noteholders, thereby eliminating the senior notes from our consolidated balance sheet on August 1, 2012.
At September 30, 2012, the balance outstanding under the Credit Agreement was $311.7 million. At September 30, 2011, the balance outstanding under the Credit Agreement was $381.2 million, of which $300.0 million was borrowed under the Term Loan Facility and $81.2 million under the Revolving Loan Facility. The interest rates of the Revolving Loan Facility are based on prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.99% and 5.00% at September 30, 2012, and 2.73% and 4.75% at September 30, 2011. The interest rate on the Term Loan Facility was based on LIBOR plus the applicable spread, resulting in an interest rate that was 3.23% at September 30, 2011. Availability under the Credit Agreement amounted to $184.0 million and $575.3 million at September 30, 2012 and 2011, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $54.3 million and $43.5 million at September 30, 2012 and 2011, respectively.
All borrowings under the Credit Agreement are generally secured by substantially all of our assets and the equity interests in all of our wholly owned subsidiaries, and loans thereunder bear interest, at our option, subject to certain limitations, at a rate equal to the following:
• | the Alternate Base Rate, which is defined as the higher of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 2.00%; or |
• | the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 3.00%. |
We are required to use 50% of the net cash proceeds (that are not applied to purchase replacement assets) from asset dispositions (other than the sale of inventory and motor vehicles in the ordinary course of business, sales of assets among us and our domestic subsidiaries and the sale or disposition of obsolete or worn-out equipment) to reduce borrowings under the Credit Agreement during any fiscal year in which unapplied net cash proceeds are in excess of $50 million.
In addition, the Credit Agreement contains various covenants limiting our ability to (subject to various exceptions), among other things:
• | grant or incur liens; |
• | incur other indebtedness (other than permitted debt as defined in the Credit Agreement); |
• | make investments, loans and acquisitions; |
• | enter into a merger, consolidation or sale of assets; |
• | enter into any sale-leaseback transaction or enter into any new business; |
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• | enter into any agreement that conflicts with the credit facility or ancillary agreements; |
• | make any change in its principles and methods of accounting as currently in effect, except as such changes are permitted by GAAP; |
• | enter into certain affiliate transactions; |
• | pay dividends or make distributions if we are in default under the Credit Agreement or in excess of available cash; |
• | permit operating lease obligations to exceed $50 million in any fiscal year; |
• | enter into any debt (other than permitted junior debt) that contains covenants more restrictive than those of the Credit Agreement or enter into any permitted junior debt that contains negative covenants more restrictive than those of the Credit Agreement; |
• | enter into hedge agreements that do not hedge or mitigate risks to which we have actual exposure; |
• | enter into put agreements granting put rights with respect to equity interests of us or our subsidiaries; |
• | prepay, redeem, defease or otherwise acquire any permitted junior debt or make certain amendments to permitted junior debt; and |
• | modify organizational documents. |
“Permitted junior debt” consists of:
• | our 8.75% senior notes due March 1, 2015 that were issued on February 2, 2009; |
• | our 7.00% senior notes due October 1, 2018 that were issued on September 27, 2010; |
• | our 6.875% senior notes due August 1, 2021 that were issued on January 19, 2011; |
• | other debt that is substantially similar to the 6.875% senior notes; and |
• | other debt of ours and our subsidiaries that is either unsecured debt, or second lien debt that is subordinated to the obligations under the Credit Agreement. |
Permitted junior debt may be incurred under the Credit Agreement so long as:
• | there is no default under the Credit Agreement; |
• | the ratio of our total funded debt to consolidated EBITDA for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.0; |
• | the debt does not mature, and no installments of principal are due and payable on the debt, prior to the maturity date of the Credit Agreement; and |
• | other than in connection with the 8.75%, 7.00% and 6.875% senior notes and other substantially similar debt, the debt does not contain covenants more restrictive than those in the Credit Agreement. |
The Credit Agreement contains the following financial covenants:
• | the ratio of our total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.0; and |
• | the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.5 to 1.0. |
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At September 30, 2012, we were in compliance with the debt covenants in the Credit Agreement and senior secured notes.
At September 30, 2012, our ratio of total funded debt to consolidated EBITDA was 2.05 to 1.0 and our ratio of consolidated EBITDA to consolidated interest expense was 23.25 to 1.0.
If we should fail to perform our obligations under these and other covenants, the Revolving Loan Facility could be terminated and any outstanding borrowings, together with accrued interest, under the Credit Agreement could be declared immediately due and payable. The Credit Agreement also has cross default provisions that apply to any other material indebtedness of ours, excluding debt of our majority-owned subsidiary, Inergy Midstream, L.P.
Each of the following is an event of default under the Credit Agreement:
• | default in payment of principal when due; |
• | default in payment of interest, fees or other amounts within three days of their due date; |
• | violation of specified affirmative and negative covenants; |
• | default in performance or observance of any term, covenant, condition or agreement contained in the Credit Agreement or any ancillary document related to the credit facility for 30 days; |
• | specified cross-defaults; |
• | bankruptcy and other insolvency events of us or our material subsidiaries; |
• | impairment of the enforceability or the validity of agreements relating to the Credit Agreement; |
• | judgments exceeding $10 million (to the extent not covered by insurance) against us or any of our subsidiaries are undischarged or unstayed for 45 consecutive days; |
• | certain defaults under ERISA that could reasonably be expected to result in a material adverse effect on us; or |
• | the occurrence of certain change of control events with respect to us. |
In conjunction with the Inergy Midstream IPO on December 21, 2011, we entered into the following transactions:
• | Entered into a $255 million unsecured promissory note with JPMorgan Chase Bank (“Promissory Note”). The promissory note was assumed by Inergy Midstream and retired in full by Inergy Midstream utilizing proceeds from the IPO. |
• | Paid in full the $300 million balance outstanding on the Term Loan Facility. |
• | Tendered for substantially all the $95 million outstanding on the 2015 Senior Notes. |
• | Tendered for $150 million of the $750 million outstanding on the 2021 Senior Notes. |
• | The debt payments described above were funded by the $255 million proceeds from the Promissory Note, proceeds received from Inergy Midstream as part of the IPO and borrowings on the Revolving Loan Facility. |
Inergy Midstream, L.P.
On December 21, 2011, Inergy Midstream entered into a $500 million, five-year revolving credit facility (“NRGM Credit Facility”). The NRGM Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The NRGM Credit Facility has an accordion feature that allows Inergy Midstream to increase the available borrowings under the facility by up to $250 million, subject to the lenders' agreement and the satisfaction of certain conditions. In addition, the NRGM Credit Facility includes a sub-limit up to $10 million for same-day swing line advances and a sub-limit up to $100 million for letters of credit.
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On April 16, 2012, Inergy Midstream exercised a portion of the accordion feature under the NRGM Credit Facility and increased the loan commitments thereunder by $100 million and as a result, the accordion feature available to Inergy Midstream is now $150 million. The aggregate amount of revolving loan commitments under the NRGM Credit Facility is now $600 million, and can be increased by up to $150 million, subject to lenders' agreement and the satisfaction of certain conditions.
At September 30, 2012, the balance outstanding under the NRGM Credit Facility was $416.5 million. Outstanding standby letters of credit under the NRGM Credit Facility amounted to $2.0 million at September 30, 2012. As a result, Inergy Midstream has approximately $181.5 million of remaining capacity at September 30, 2012, subject to compliance with any applicable covenants under such facility.
The NRGM Credit Facility contains various covenants and restrictive provisions that limit Inergy Midstream's ability to, among other things:
• | incur additional debt; |
• | make distributions on or redeem or repurchase units; |
• | make certain investments and acquisitions; |
• | incur or permit certain liens to exist; |
• | enter into certain types of transactions with affiliates; |
• | merge, consolidate or amalgamate with another company; and |
• | transfer or otherwise dispose of assets. |
If Inergy Midstream fails to perform its obligations under these and other covenants, the lenders' credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under its credit facility could be declared immediately due and payable. The NRGM Credit Facility also has cross default provisions that apply to any other material indebtedness of Inergy Midstream.
Borrowings under the NRGM Credit Facility are generally secured by pledges of the equity interests in Inergy Midstream's wholly owned subsidiaries, liens on substantially all of its assets and guarantees issued by all of Inergy Midstream's subsidiaries. Borrowings under the NRGM Credit Facility (other than swing line loans) will bear interest at its option at either:
• | the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 1.75% depending on Inergy Midstream's most recent total leverage ratio; or |
• | the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 2.75% depending on Inergy Midstream's most recent total leverage ratio. |
Swing line loans bear interest at the Alternate Base Rate plus a margin varying from 0.75% to 1.75%. The unused portion of the NRGM Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to Inergy Midstream's most recent total leverage ratio. Interest on Alternative Base Rate loans is payable quarterly or, if the Adjusted LIBO Rate applies, it may be paid at more frequent intervals.
The NRGM Credit Facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.00.
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Senior Unsecured Notes
2015 Senior Notes
In conjunction with the Inergy Midstream IPO on December 21, 2011, we tendered for substantially all the $95 million outstanding on these notes, leaving a balance of $0.8 million at September 30, 2012.
2018 Senior Notes
On September 27, 2010, we and our wholly-owned subsidiary, Inergy Finance Corp, issued $600 million aggregate principal amount of 7% senior unsecured notes due 2018 (the "2018 Senior Notes") under Rule 144A to eligible purchasers. The 2018 Senior Notes mature on October 1, 2018.
The majority of these notes were exchanged during the year ended September 30, 2012 in conjunction with the contribution of our retail propane operations to SPH, leaving a balance of $10.1 million at September 30, 2012.
2021 Senior Notes
As discussed above, in conjunction with the Inergy Midstream IPO on December 21, 2011, we tendered for $150 million of the $750 million outstanding on these notes. The majority of the remaining notes were exchanged during the year ended September 30, 2012, in conjunction with the contribution of our retail propane operations to SPH, leaving a balance of $0.6 million at September 30, 2012.
In conjunction with the contribution of our retail propane operations to SPH, we solicited noteholder consents to remove all the restrictive covenants in the senior notes indentures.
See Note 8 for a discussion related to our Senior Unsecured Notes.
Recent Accounting Pronouncements
In June 2011 the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). Under ASU 2011-05, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under both options, an entity will be required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. Furthermore, regardless of the presentation methodology elected, the entity will be required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05" ("ASU 2011-12") which deferred this requirement in order to allow the FASB more time to determine whether reclassification adjustments should be required to be presented on the face of the financial statements. The amendments contained in ASUs 2011-05 and 2011-12 do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments also do not affect how earnings per share is calculated or presented. We adopted ASUs 2011-05 and 2011-12 in the fourth quarter of the year ended September 30, 2012. We elected to present the total of comprehensive income in two separate but consecutive statements.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS" ("ASU 2011-04"). The amended guidance does not modify the requirements for when fair value measurements apply, rather it generally represents clarifications on how to measure and disclose fair value under ASC Topic 820 (Fair Value Measurements and Disclosures). Respective disclosure requirements are essentially the same. However, some of the specific amendments address the application of existing fair value measurement requirements and expand certain other disclosure requirements, particularly pertaining to level 3 fair value measurements. ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. We adopted ASU 2011-04 in the first quarter of the year ended September 30, 2012. The adoption of this guidance did not have an impact on our consolidated financial statements.
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In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”), which is included in the ASC Topic 820 (Fair Value Measurements and Disclosures). ASU 2010-06 requires new disclosures on the amount and reason for transfers in and out of level 1 and level 2 fair value measurements. ASU 2010-06 also requires disclosure of activities, including purchases, sales, issuances and settlements within the level 3 fair value measurements and clarifies existing disclosure requirements on levels of disaggregation and disclosures about inputs and valuation techniques. We have previously adopted the new disclosures for transfers in and out of level 1 and level 2. The new disclosures for level 3 were adopted on October 1, 2011, as disclosed in Note 7.
Critical Accounting Policies
Accounting for Price Risk Management. We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of commodity will be available; and (iii) manage our exposure to interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.
We determine fair value of our derivative financial instruments according to the following hierarchy: (1) comparable market prices to the extent available; (2) internal valuation models that utilize market data (observable inputs) as input variables; and lastly, (3) internal valuation models that use management’s assumptions about the assumptions that market participants would use in pricing the instruments (unobservable inputs) to the extent (1) and (2) are unavailable. Because the majority of the instruments we enter into are traded in liquid markets, we value these instruments based on prices indicative of exiting the position. As a consequence, the majority of the values of our derivative financial instruments are based upon actual prices of like kind trades that are obtained from on-line trading systems and verified with broker quotes. Changes in the fair value of these derivative financial instruments, primarily resulting from variability in supply and demand, are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.
On the date the derivative contract is entered into, we generally designate specific derivatives as either a hedge of the fair value of a recognized asset or liability (fair value hedge), or a hedge of a forecasted transaction (cash flow hedge). We document all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. We use regression analysis to assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that is has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge, we continue to carry the derivative on the balance sheet at fair value, and recognize changes in the fair value of the derivative through current-period earnings.
We are party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges. We are also periodically party to certain interest rate swap agreements designed to manage interest rate risk exposure. Our overall objective for entering into fair value hedges is to manage our exposure to fluctuations in commodity prices and changes in the fair market value of our inventories and fixed rate borrowings. The commodity derivatives are recorded at fair value on the balance sheet as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold. The interest rate derivatives are recorded at fair value on the balance sheets in other assets or liabilities and the related change in fair value is recorded to earnings in the current period as interest expense.
Any ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. We recognized a $0.5 million, $1.8 million and $0.4 million net gain in the years ended September 30, 2012, 2011 and 2010, respectively, related to the ineffective portion of our fair value hedging instruments. In addition, for the years ended September 30, 2012 and 2011, we recognized no gain, and for the year ended September 30, 2010, we recognized a net loss of $0.1 million related to the portion of fair value hedging instruments that we excluded from our assessment of hedge effectiveness.
We also enter into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts and variable interest payments. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner’s capital and reclassified into earnings in the same period in which the hedge transaction affects earnings. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product sold in the current period.
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Accumulated other comprehensive income (loss) was $(14.9) million and $(6.7) million at September 30, 2012 and 2011, respectively. Included in accumulated other comprehensive loss at September 30, 2012 was a loss of $7.4 million attributable to commodity instruments and a loss of $7.5 million attributable to interest rate swaps. Approximately $6.9 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months.
Our policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement.
The cash flow impact of derivative financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.
Revenue Recognition. Sales of propane, other liquids and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. Gas processing and fractionation fees are recognized upon delivery of the product. Revenue from the sale of propane appliances and equipment is recognized at the time of delivery. Revenue from repairs and maintenance is recognized upon completion of the service. Revenues from storage and transportation contracts are recognized during the period in which the services are provided. Revenues from salt are recognized when product is shipped to the customer or when certain contractual performance requirements have otherwise been met.
Impairment of Goodwill and Long-Lived Assets. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.
We completed the valuation of each of our reporting units and determined no impairment existed as of September 30, 2012. The valuation of our reporting units requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. A 10% decrease in the estimated future cash flows and a 1% increase in the discount rate used in our impairment analysis would not have indicated a potential impairment of any of our intangible assets.
The value of the assets to be disposed of is estimated at the date a commitment to dispose the asset is made. Our estimate of any loss associated with an asset sale is dependent on certain assumptions we make with respect to the net realizable value of the particular asset.
Self-Insurance. We are insured by third parties for both ourselves and Inergy Midstream, subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Our self insurance reserves could be affected if future claims development differs from the historical trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. We are liable for the development of claims for our disposed retail propane operations, provided they were reported prior to August 1, 2012. At September 30, 2012 and 2011, our self-insurance reserves were $23.8 million and $20.6 million, respectively. We estimate that $15.0 million of this balance will be paid subsequent to September 30, 2013. As such, $15.0 million has been classified in other long-term liabilities on the consolidated balance sheets.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
We have a revolving line of credit subject to the risk of loss associated with movements in interest rates. At September 30, 2012, we had floating rate obligations totaling $86.7 million borrowed under our revolving line of credit (net of certain interest rate swaps, which convert our revolving line of credit to a fixed rate). Inergy Midstream also has a revolving credit facility subject to the risk of loss associated with movements in interest rates. At September 30, 2012, Inergy Midstream had floating rate obligations totaling $416.5 million. Floating rate obligations expose us and Inergy Midstream to the risk of increased interest expense in the event of increases in short-term interest rates.
During fiscal year 2011, we entered into eleven interest rate swaps, one of which was scheduled to mature in 2015 (notional amount of $25 million) and the remaining ten were scheduled to mature in 2018 (aggregate notional amount of $250 million). In August 2011, our ten interest rate swaps maturing in 2018 were terminated. In December 2011, the remaining interest rate swap maturing in 2015 was terminated and we entered into a new interest rate swap scheduled to mature in 2018 (notional amount of $50 million). This swap agreement, which was to expire on the same date as the maturity date of the related senior unsecured notes and contained call provisions consistent with the underlying senior unsecured notes, required the counterparty to pay us an amount based on the stated fixed interest rate due every nine months. In exchange, we were required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the one-month LIBOR interest rate plus a spread of 5.218% applied to the same aggregate notional amount of $50 million. This swap agreement had been accounted for as a fair value hedge. Amounts received or paid under the agreement were accrued and recognized over the life of the agreement as an adjustment to interest expense. In May 2012, this interest rate swap was terminated.
We are party to six interest rate swap agreements scheduled to mature in 2015 to hedge our exposure to variable interest payments due under the Credit Agreement. Certain of these swap agreements with a notional amount of $100 million do not commence quarterly settlements until October 1, 2012. These swap agreements require us to pay the counterparty an amount based on fixed rates from 0.84% to 2.52% due quarterly. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to us based on the three-month LIBOR applied to the same aggregate notional amount of $225 million. These swap agreements have been accounted for as cash flow hedges.
If the floating rate of our revolving line of credit were to fluctuate by 100 basis points from September 2012 levels, our interest expense would change by approximately $0.9 million per year. If the floating rate of Inergy Midstream's revolving line of credit were to fluctuate by 100 basis points from September 2012 levels, Inergy Midstream's interest expense would change by approximately $4.2 million per year.
Commodity Price, Market and Credit Risk
Inherent in our NGL marketing, supply and logistics business are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2012 and 2011, were energy marketers, propane retailers, resellers, and dealers.
We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our marketing customers. However, we may experience net unbalanced positions from time to time, which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.
We rarely take title to any commodity in our storage and transportation business.
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Fair Value
The fair value of the derivatives and inventory exchange contracts related to price risk management activities as of September 30, 2012, and September 30, 2011, were assets of $37.5 million and $17.1 million, respectively, and liabilities of $20.9 million and $19.0 million, respectively.
We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Our risk management department regularly compares valuations to independent sources and models on a quarterly basis.
Sensitivity Analysis
A theoretical change of 10% in the underlying commodity value would result in a $0.1 million change in the market value of the contracts as there were 0.6 million gallons of net unbalanced positions at September 30, 2012.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the financial statements and report of independent registered public accounting firm included later in this report under Item 15.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
We maintain controls and procedures designed to provide a reasonable assurance that information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officer and the Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of September 30, 2012, at the reasonable assurance level. There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the period ended September 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Changes in Internal Control over Financial Reporting
In fiscal 2012, we completed the acquisitions of Papco and Werner. See Note 3 “Acquisitions” for a discussion of the acquisitions and related financial data.
We are currently in the process of evaluating the internal controls and procedures of our current acquisitions. Further, we are in the process of integrating their operations. Management will continue to evaluate our internal control over financial reporting as we execute integration activities, however, integration activities could materially affect our internal control over financial reporting in future periods.
Additionally, we contributed our retail propane operations to SPH effective August 1, 2012. As a result, the internal controls and procedures surrounding retail propane operations were discontinued at that time. Those controls and procedures were in effect for the period through our closing of the July 31, 2012 financial statements.
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Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, pursuant to Exchange Act Rules 13a-15(f). Our internal control system was designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements in accordance with GAAP.
Management recognizes that there are inherent limitations in the effectiveness of any system of internal control, and accordingly, even effective internal control can provide only reasonable assurance with respect to financial statement preparation and fair presentation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the operations resulting from the fiscal 2012 acquisitions (collectively the "Acquisitions”), which are included in the 2012 consolidated financial statements. The financial reporting systems of the Acquisitions were integrated into the Company’s financial reporting systems throughout 2012. Therefore, the Company did not have the practical ability to perform an assessment of their internal controls in time for this current year-end. The Company fully expects to include the Acquisitions in next year’s assessment. The Acquisitions constituted $22.3 million and $44.9 million in total assets and revenues, respectively, in the consolidated financial statements.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2012. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based upon our assessment, we conclude that, as of September 30, 2012, our internal control over financial reporting is effective, based upon those criteria.
Our independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated November 20, 2012, on the effectiveness of our internal control over financial reporting, which is included herein.
Item 9B. Other Information.
None.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Our General Partner Manages Inergy, L.P.
Inergy GP, LLC, our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, including units held by the general partner and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for specific nonrecourse indebtedness or other obligations. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse.
As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers of our general partner and are subject to the oversight of the directors of our general partner. The board of directors of our general partner is presently composed of five directors.
Directors and Executive Officers
The following table sets forth certain information with respect to the executive officers and members of the board of directors of our general partner. Executive officers and directors will serve until their successors are duly appointed or elected.
Executive Officers and Directors | Age | Position with our General Partner | |||
John J. Sherman | 57 | Chief Executive Officer and Director | |||
Phillip L. Elbert | 54 | Executive Vice President—Strategy and Director | |||
R. Brooks Sherman, Jr. | 47 | President | |||
Michael J. Campbell | 43 | Senior Vice President—Chief Financial Officer | |||
Laura L. Ozenberger | 54 | Senior Vice President—General Counsel and Secretary | |||
William C. Gautreaux | 49 | President—Inergy Services | |||
Michael D. Lenox | 36 | Vice President—Chief Accounting Officer | |||
Warren H. Gfeller | 60 | Director | |||
Arthur B. Krause | 71 | Director | |||
Robert D. Taylor | 65 | Director | |||
John J. Sherman. Mr. Sherman has served as Chief Executive Officer and a director since March 2001. He served as Chief Executive Officer, President and director from March 2001 until September 2012 and of our predecessor from 1997 until July 2001. Prior to joining our predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. He was responsible for all downstream propane marketing operations, which at the time were the country's largest. From 1991 through 1996, Mr. Sherman was the president of LPG Services Group, Inc., a company he co-founded and grew to become one of the nation's largest wholesale marketers of propane before Dynegy acquired LPG Services in 1996. From 1984 through 1991, Mr. Sherman was a vice president and member of the management committee of Ferrellgas. He also served as President, Chief Executive Officer and director of Inergy Holdings GP, LLC and is currently a director of Great Plains Energy Inc. and Chief Executive Officer, President and director of NRGM GP, LLC. We believe the breadth of Mr. Sherman's experience in the energy industry, through his current position as the CEO and his past employment described above, as well as his current board of director positions, has given him valuable knowledge about our business and our industry that makes him an asset to the board of directors of Inergy GP.
Phillip L. Elbert. Mr. Elbert has served as Executive Vice President - Strategy since September 2012. Mr. Elbert served as President and Chief Operating Officer-Propane Operations from September 2007 until August 2012 and Executive Vice President-Propane Operations and director since March 2001. He joined our predecessor as Executive Vice President-Operations in connection with our acquisition of the Hoosier Propane Group in January 2001. Mr. Elbert joined the Hoosier Propane Group in 1992 and was responsible for overall operations, including Hoosier's retail, wholesale and transportation divisions. From 1987 through 1992, he was employed by Ferrellgas, serving in a number of management positions relating to retail, transportation and supply. Prior to joining Ferrellgas, he was employed by Buckeye Gas Products, a large propane
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marketer from 1981 to 1987. He also served as the President and Chief Operating Officer-Propane Operations of Inergy Holdings GP, LLC and is currently Executive Vice President - Strategy of NRGM GP, LLC. Through his various leadership positions described above, Mr. Elbert has gained valuable experience in evaluating the financial performance and operations of companies in the energy industry, which makes him a valuable member of the board of directors of Inergy GP.
R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has served as President since September 2012. He served as Executive Vice President since September 2007, Senior Vice President since September 2002 and Chief Financial Officer since March 2001. Mr. Sherman previously served as Vice President from March 2001 until September 2002. He joined our predecessor in December 2000 as Vice President and Chief Financial Officer. From 1999 until joining our predecessor, he served as Chief Financial Officer of MCM Capital Group. From 1996 through 1999, Mr. Sherman was employed by National Propane Partners, a publicly traded master limited partnership, first as its controller and chief accounting officer and subsequently as its chief financial officer. From 1995 to 1996, Mr. Sherman served as chief financial officer for Berthel Fisher & Co. Leasing Inc. and prior to 1995, Mr. Sherman was in public accounting with Ernst & Young and KPMG Peat Marwick. He also served as Executive Vice President and Chief Financial Officer of Inergy Holdings GP, LLC and currently serves as an Executive Vice President of NRGM GP, LLC.
Michael J. Campbell. Mr. Campbell has served as the Senior Vice President - Chief Financial Officer since September 2012. He joined the company in 2002 and served as the Vice President and Treasurer since May 2005. He previously served as Director of Financial Analysis in the Corporate Development department at Aquila, Inc., and as Manager of Crude and Structured Products Trading Support at Koch Industries. He also currently serves as Senior Vice President - Chief Financial Officer of NRGM GP, LLC.
Laura L. Ozenberger. Ms. Ozenberger has served as Senior Vice President-General Counsel and Secretary since September 2007 and Vice President-General Counsel and Secretary since February 2003. From 1990 to 2003, Ms. Ozenberger worked for Sprint Corporation. While at Sprint, Ms. Ozenberger served in a number of management roles in the Legal and Finance departments. Prior to 1990, Ms. Ozenberger was in a private legal practice. She also served as Senior Vice President - General Counsel and Secretary of Inergy Holdings GP, LLC and currently serves as Senior Vice President - General Counsel and Secretary for NRGM GP, LLC.
William C. Gautreaux. Mr. Gautreaux has served as President - Inergy Services since November 2011. He has been with the company since it inception in 1997 and manages Inergy's coast-to-coast NGL supply and logistics business. Prior to joining the company Mr. Gautreaux was employed by Ferrellgas and later co-founded and managed supply and risk management for LPG Services Group, Inc., which was acquired by Dynegy in 1996. Mr. Gautreaux also serves as the President - Inergy Services for NRGM GP, LLC.
Michael D. Lenox. Mr. Lenox has served as Vice President and Chief Accounting Officer since September 2012. Mr. Lenox joined the company in September 2007 as its Director of Financial Reporting and served as the Vice President and Corporate Controller since November 2011. Prior to joining the company, Mr. Lenox was in public accounting with Ernst & Young. Mr. Lenox also serves as the Vice President and Chief Accounting Officer for NRGM GP, LLC.
Warren H. Gfeller. Mr. Gfeller has been a member of our general partner's board of directors since March 2001. He was a member of our predecessor's board of directors from January 2001 until July 2001. He has engaged in private investments since 1991. From 1984 to 1991, Mr. Gfeller served as president and chief executive officer of Ferrellgas, Inc., a retail and wholesale marketer of propane and other NGLs. Mr. Gfeller began his career with Ferrellgas in 1983 as an executive vice president and financial officer. Prior to joining Ferrellgas, Mr. Gfeller was the Chief Financial Officer of Energy Sources, Inc. and a CPA at Arthur Young & Co. He also served as a director of Inergy Holdings GP, LLC, Zapata Corporation and Duckwall-Alco Stores, Inc. and currently serves as a member of the board of directors of NRGM GP, LLC. Mr. Gfeller worked for many years in the energy industry. This experience has given him a unique perspective on our operations, and, coupled with his extensive financial and accounting training and practice, has made him a valuable member of the board of directors of Inergy GP.
Arthur B. Krause. Mr. Krause has been a member of our general partner's board of directors since May 2003. Mr. Krause retired from Sprint Corporation in 2002, where he served as Executive Vice President and Chief Financial Officer from 1988 to 2002. He was President of United Telephone-Eastern Group from 1986 to 1988. From 1980 to 1986, he was Senior Vice President of United Telephone System. He currently serves as a director of Westar Energy and NRGM GP, LLC and served as a director of Inergy Holdings GP, LLC from April 2005 until November 2010. Mr. Krause's prior leadership experience and his extensive financial and accounting training and practice have made him a valuable member of the board of directors of Inergy GP.
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Robert D. Taylor. Mr. Taylor joined our general partner's board of directors in May 2005. Mr. Taylor, a CPA, has served as chief executive officer of Executive AirShare Corporation since November 2001. Mr. Taylor also served as president of Executive AirShare Corporation from November 2001 until November 2007. From August 1998 until September 2001, Mr. Taylor was president of Executive Aircraft Corporation. Mr. Taylor serves as a director of Blue Valley BanCorp. and Elecsys Corporation and previously served as a director of Commercial Federal Corporation. The breadth of Mr. Taylor's operational, financial and business experience has developed through his experience as chief executive officer of Executive AirShare Corporation and makes him an important voice as an independent director on the board of directors of Inergy GP.
Independent Directors
Messrs. Gfeller, Krause, and Taylor qualify as “independent” pursuant to independence standards established by the New York Stock Exchange ("NYSE") as set forth in Section 303A.02 of its Listed Company Manual. To be considered an independent director under the NYSE listing standards, the board of directors must affirmatively determine that a director has no material relationship with the Partnership. In making this determination, the board of directors adheres to all of the specific tests for independence included in the NYSE listing standards and considers all other facts and circumstances it deems necessary or advisable.
Board Leadership Structure and Risk Oversight
Board Leadership Structure
The board has no policy that requires that the positions of the Chairman of the Board (the “Chairman”) and the Chief Executive Officer be separate or that they be held by the same individual. The board believes that this determination should be based on circumstances existing from time to time, including the composition, skills and experience of the board and its members, specific challenges faced by the company or the industry in which it operates, and governance efficiency. Based on these factors, John J. Sherman serves as our Chairman and Chief Executive Officer.
Our non-management directors meet in regularly scheduled sessions. Our non-management directors have appointed Warren H. Gfeller as the lead director to preside at such meetings. We have established a procedure by which unitholders or interested parties may communicate directly with the board of directors, any committee of the board, any of the independent directors or any one director serving on the board of directors by sending written correspondence addressed to the desired person, committee or group to the attention of Laura Ozenberger at Inergy, L.P., Two Brush Creek Blvd., Suite 200, Kansas City, MO 64112. Communications are distributed to the board of directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.
Risk Oversight
We face a number of risks, including environmental and regulatory risks, and others, such as the impact of competition. Management is responsible for the day-to-day management of risks our company faces, while the board of directors, as a whole and through its committees, has responsibility for the oversight of risk management. In fulfilling its risk oversight role, the board of directors must determine whether risk management processes designed and implemented by our management are adequate and functioning as designed. Senior management regularly delivers presentations to the board of directors on strategic matters, operations, risk management and other matters, and is available to address any questions or concerns raised by the board. Specifically, at quarterly board meetings, senior management delivers a presentation on risk management focused on one or more key aspects of our business as selected by the board or senior management. Board meetings also regularly include discussions with senior management regarding strategies, key challenges and risks and opportunities for our company.
Our board committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists with risk management oversight in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The compensation committee assists the board of directors with risk management relating to our compensation policies and programs.
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Board Committees
Audit Committee
The members of the audit committee are Arthur B. Krause, Warren H. Gfeller and Robert D. Taylor. Our board has determined that each of the members of our audit committee meet the independence standards of the NYSE and that Mr. Gfeller is an audit committee financial expert based upon the experience stated in his biography. We believe that he is independent of management. The audit committee's primary responsibilities are to monitor: (a) the integrity of our financial reporting process and internal control system; (b) the independence and performance of the independent registered public accounting firm; and (c) the disclosure controls and procedures established by management. Our audit committee charter may be found on our website at www.inergylp.com.
Conflicts Committee
Our general partner may appoint two independent directors to serve on a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. A conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence standards for service on an audit committee of a board of directors, which standards are established by the NYSE. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
Compensation Committee
Although we are not required by NYSE listing standards to have a compensation committee, two members of our board of directors also serve as members of our compensation committee, which oversees compensation decisions for the officers of Inergy GP, LLC, as well as the compensation plans described below. The members of the compensation committee are Warren H. Gfeller and Arthur B. Krause. Our compensation committee charter may be found on our website at www.inergylp.com.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our company's directors and executive officers, and persons who own more than 10% of any class of equity securities of our company registered under Section 12 of the Exchange Act, to file with the SEC initial reports of ownership and report of changes in ownership in such securities and other equity securities of our company. SEC regulations require directors, executive officers and greater than 10% unitholders to furnish our company with copies of all Section 16(a) reports they file. To our knowledge, based solely on review of the reports furnished to us and written representations that no other reports were required, during the fiscal year ended September 30, 2012, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.
Code of Ethics
We have adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, as well as to all of our other employees. Additionally, the board of directors has adopted corporate governance guidelines for the directors and the board. The code of ethics and corporate governance guidelines may be found on our website at www.inergylp.com.
Item 11. Executive Compensation.
Compensation Discussion and Analysis
Introduction
We do not directly employ any of the persons responsible for managing our business. Inergy GP, LLC, our general partner, manages our operations and activities, and its board of directors and officers make decisions on our behalf. The compensation of the directors and certain officers of our general partner is determined by the compensation committee of the board of directors of our general partner. Our executive officers also serve in similar capacities as executive officers of NRGM GP, LLC, the general partner of Inergy Midstream, L.P. and the compensation of the named executive officers discussed below reflects total compensation for services to all Inergy entities. Our general partner has entered into an Omnibus Agreement with
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us, NRGM GP, LLC and Inergy Midstream, L.P. wherein our general partner is reimbursed for, among other things, salaries and related benefits and expenses of persons employed by our general partner or its affiliates who render services to Inergy Midstream, L.P. and its affiliates.
For purposes of this Compensation Discussion and Analysis our named executive officers are John J. Sherman, R. Brooks Sherman, Jr., Michael J. Campbell, William C. Gautreaux, William R. Moler and Laura L. Ozenberger. William R. Moler is included as a named executive officer because he was an executive officer as of September 30, 2012; however, he resigned from our general partner effective as of October 5, 2012.
Compensation Philosophy and Objectives
We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our performance long-term is our ability to increase sustainable cash distributions to our unitholders and the related unitholder value realized. We believe that by tying a substantial portion of each named executive officer's total compensation to financial performance metrics based on such distributions and unitholder value, our pay-for-performance approach aligns the interests of executive officers with that of our unitholders. Accordingly, the objectives of our total compensation program consist of:
• | aligning executive compensation incentives with the creation of unitholder value and the growth of cash earnings on behalf of our unitholders; |
• | balancing short and long-term performance; |
• | tying short-and long-term compensation to the achievement of performance objectives (company, business unit, department and/or individual); and |
• | attracting and retaining the best possible executive talent for the benefit of our unitholders. |
By accomplishing these objectives, we hope to optimize long-term unitholder value.
Compensation Setting Process
Chief Executive Officer's Role in the Compensation Setting Process
Our Chief Executive Officer plays a significant role in the compensation setting process. The most significant aspects of his role are:
• | assisting in establishing business performance goals and objectives; |
• | evaluating executive officer and company performance; |
• | recommending compensation levels and awards for executive officers other than himself; and |
• | implementing the approved compensation plans. |
The Chief Executive Officer makes recommendations to the compensation committee with respect to financial metrics to be used for performance-based awards as well as other recommendations regarding non-CEO executive compensation, which may be based on our performance, individual performance and the peer group compensation market analysis. The compensation committee considers this information when establishing the total compensation package of the executive officers. The Chief Executive Officer's performance and compensation is reviewed, evaluated and established separately by the compensation committee based on criteria similar to those used for non-CEO executive compensation.
Market Analysis
To evaluate the competitiveness of both total executive compensation and the individual compensation components, the compensation committee utilizes compensation data about other companies to assist in assessing executive compensation levels, including the individual base salary and incentive components. The data typically consists of an analysis of total compensation, as well as base salary amounts, annual incentive awards, and long-term incentive awards and is compiled from public filings of similar companies, as well as companies in the Kansas City region. We selected these “peer” companies because, like us, they are: (i) MLPs with significant NGL or natural gas transportation and storage operations, or (ii) MLPs with growing midstream operations. We chose the regional companies because they are public companies with which we compete for talent in the local employment market.
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“Peer” MLP Companies | Regional Companies | |
Tesoro Logistics, L.P | DST Systems, Inc. | |
Copano Energy, LLC | Great Plains Energy Incorporated | |
Markwest Energy Partners, L.P. | Kansas City Southern | |
Plains All American Pipeline, L.P. | Ferrellgas Partners, L.P. | |
Regency Energy Partners, L.P. | ||
Targa Resources Partners, L.P. | ||
Energy Transfer Partners, L.P. | ||
The compensation committee utilizes the market data as a general guideline in making compensation-related decisions. When determining compensation amounts for our executive officers, the compensation committee uses data from our “peer” group as a reference for determining:
• | amount of total compensation; |
• | individual components of compensation; and |
• | relative proportion of each component of compensation - base salary, annual incentive award opportunity and long-term incentive award value. |
While our general objective for total compensation is at or above the median of the “peer” group data with a significant portion of total compensation at risk, we do not require a strict policy of achieving a specific percentile relationship of actual pay to market pay as some companies do. The compensation committee has the full discretion to disregard the market data and award compensation at a different range if there are factors warranting the adjustment. Such factors may include alignment of the officer's position within the “peer” group data, experience and value he or she brings to the role, sustained high-level performance, demonstrated success in meeting key financial and other business objectives and the amount of the officer's pay relative to the pay of his or her peers within our company.
In addition, the actual value delivered to any executive may be above or below that range depending upon our financial results, common unit price performance and the individual's performance.
The compensation committee may in its discretion retain the services of a third-party compensation consultant, but did not retain any such consultants during the fiscal year.
In collecting the peer group data for the compensation committee for fiscal 2012, we compared each officer's position against like positions for our “peer” group. The data was adjusted for differences in various financial and operating metrics, including revenues, customer base, numbers of employees and scope for each position relative to comparator company positions. Based on the difficulty in assessing appropriate comparisons of relative value for equity awards, no specific comparison of equity awards of our “peer” companies was made for long-term incentive opportunity values although the market value of equity holdings of similarly situated employees at our “peer” companies was generally considered.
Elements of Compensation
The principal elements of compensation for the named executive officers are the following:
• | base salary; |
• | incentive awards; |
• | long-term incentive plan awards; and |
• | retirement and health benefits. |
Base Salary
Base salary is designed to compensate executives for the responsibility of the level of the position they hold and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). Base salary amounts were initially established in the employment agreements of our named executive officers and we historically have not made annual adjustments to the salaries of our named executive officers. We do, however, review the salaries of our named executive officers on an annual basis as well as at the time of promotion, or when entering into or renewing an employment agreement and may adjust salaries due to changes in responsibilities or market conditions. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of the base salary
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amounts of the named executive officers as compared to the compensation of executives in similar positions with similar responsibility levels in our industry and in our region. However, the final determination of base salary amounts is within the compensation committee's subjective discretion.
Consistent with its general policy of not making any systematic or annual adjustments to base salary, the compensation committee elected not to make any broad based changes to the annual base salaries of our named executive officers for the upcoming fiscal year. As a result, base salaries of each of John J.Sherman, William C. Gautreaux, and Laura L. Ozenberger remained $400,000, $250,000 and $250,000, respectively. The compensation committee determined that the base salaries for R. Brooks Sherman, Jr. and Michael J. Campbell should be increased to $365,000 (effective November 1, 2012) and $250,000 (effective October 1, 2012), respectively. We believe the increases are warranted based on (i) the increased responsibilities of these executives in their new roles as President (R. Brooks Sherman, Jr.) and Chief Financial Officer (Michael J. Campbell) and (ii) comparable compensation of executives in similar positions with similar responsibility levels in our industry and our region.
Incentive Awards
Incentive awards are designed to reward the performance of key employees, including the named executive officers, by providing annual incentive opportunities for the partnership's achievement of its annual financial performance goals. In particular, these bonus awards are provided to the named executive officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of our short-term business objectives. Under the terms of their respective employment agreements, each named executive officer is eligible, upon the achievement of certain subjective and objective criteria, to receive a cash incentive award in amount up to 100% of the named executive officer's base salary.
The sole metric used to determine whether bonuses would be paid to the named executive officers in fiscal 2012 was our achievement of the target of earnings before income taxes, plus net interest expense, depreciation and amortization expense, further adjusted to exclude the gain or loss on derivative contracts associated with retail propane fixed price sales contracts, the gain or loss on the disposal of assets, long-term incentive and equity compensation expenses and transaction costs (“Adjusted EBITDA”). We selected this metric because we believe it closely aligns the focus of our named executive officers with the increase in unitholder value. In addition, this target was communicated to our unitholders and analysts as guidance at the beginning of the 2012 fiscal year.
We did not meet the target of $414 million for Adjusted EBITDA in fiscal 2012. Accordingly, in accordance with the terms of the employment agreements of the named executive officers, there were no short-term incentive plan awards for fiscal 2012.
In addition, upon recommendation from the Chief Executive Officer, the compensation committee may make discretionary cash bonus awards to the named executive officers. The awards are designed to award outstanding individual performance in the fiscal year. In fiscal 2012, R. Brooks Sherman, Jr., Michael J. Campbell, William C. Gautreaux, and Laura L. Ozenberger were awarded discretionary cash bonus awards of $500,000, $200,000, $300,000 and $250,000, respectively. These bonuses were awarded primarily based on these individuals' substantial efforts in repositioning the partnership into a pure midstream company. These efforts include the Inergy Midstream initial public offering, the drop down of US Salt, LLC and the sale of our retail propane business.
Long-Term Incentive Plan Awards
Long-term incentive awards for the named executive officers are granted under the Inergy Long Term Incentive Plan and Inergy Midstream, L.P. Long Term Incentive Plan (both of which are described in more detail below) in order to promote achievement of our primary long-term strategic business objective of increasing distributable cash flow and increasing unitholder value. These plans are designed to align the economic interests of key employees and directors with those of our common unitholders and the common unitholders of Inergy Midstream, L.P. and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us and in Inergy Midstream, L.P. and consisted solely of grants of restricted units during the 2012 fiscal year. We have no policy regarding the allocation of different types of equity awards; rather, we determine which type of award will be granted due to a number of different factors, including, cost to the company, perceived value to the employee and economic conditions.
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We have not made systematic annual awards to the named executive officers. Generally, we believe that a two- to five-year grant cycle (and complete vesting over five years) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officers. New awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of the named executive officers.
In determining the size of the equity awards, the compensation committee primarily considers the grant date value and vesting schedule of the awards as both a retention tool and performance incentive, the experience and skills of the executive officers as well as their contributions to our operational and financial performance, the economic and retention value of outstanding equity awards held by the executives, the amount of cash distributions that would be received by the executives and cost to our company. These factors were not given any specific weight; rather, they were subjectively evaluated by the compensation committee. The value of the equity was also compared to the equity awards of our “peer” companies to assess reasonableness of the awards without imposing specific targets.
On May 2, 2012, the compensation committee of the board of directors of Inergy Midstream, L.P.'s general partners awarded Mr. R. Brooks Sherman, Jr., Mr. Campbell, Mr. Gautreaux, Ms. Ozenberger, and Mr. Moler, 50,000, 20,000, 30,000, 40,000 and 40,000 Inergy Midstream, L.P. restricted units, respectively. The awards were made shortly following the initial public offering of Inergy Midstream, L.P. to better align the economic interests of these key employees with Inergy Midstream, L.P. common unitholders and to provide incentive for these key individuals to remain employed with us. These awards vest 25%, 25% and 50% on the third, fourth and fifth anniversaries, respectively, from the date of grant. Additionally, in November 2012, the compensation committee approved awards to Mr. R. Brooks Sherman, Jr., Mr. Campbell, Mr. Gautreaux and Ms. Ozenberger of 25,000, 10,000, 15,000, and 12,500 Inergy, L.P. restricted units, respectively. These awards will vest ratably over three years beginning one year from the date of grant. The restricted units were awarded to compensate these individuals for their substantial efforts in repositioning the partnership into a pure midstream company and to further assure the continued employment of these key individuals as the partnership continues to grow.
In February 2010 we approved a grant of 231,700 restricted units to Phillip L. Elbert and 182,050 restricted units to R. Brooks Sherman. In January 2011 we approved a grant of 80,000 restricted units to Laura L. Ozenberger Theses awards were subject to forfeiture if on any vesting date the annualized distribution of an Inergy, L.P. common unit is less than $2.74. Since granting these awards our operations have changed significantly. With the sale of the retail propane operations, the company has been transformed into a smaller midstream focused company. Furthermore, we believe that these restricted units represent an important compensation component to the named executive officers. Based on the foregoing, in November 2012, the Compensation Committee modified the annualized distribution target to $1.16.
On September 14, 2012, in connection with the sale of our retail propane business discussed in Item 1 - Introduction, we distributed approximately 14.1 million SPH common units to Inergy, L.P. unitholders. In lieu of SPH units, restricted unitholders, including certain named executive officers, received a cash payment in an amount equal to the number of SPH units such holder would have received as part of the distribution, multiplied by the closing price of an SPH unit on the distribution date.
Risk Assessment Related to our Compensation Structure.
We believe that the compensation plans and programs for our executive officers, as well as other employees, are appropriately structured and are not reasonably likely to result in a material risk. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could reward poor judgment. We also believe that we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of an operating segment. We generally determine whether, and to what extent, executive officers and other employees receive incentive cash bonuses based on achievement of specified financial performance objectives. For example, in fiscal 2012, Inergy announced EBITDA guidance that it believed was reasonable in light of past performance and market conditions, and the compensation committee took into account whether we met or exceeded that public guidance for the purpose of determining incentive cash bonuses for its executive officers following the completion of the fiscal year. Furthermore, we use restricted units rather than unit options for equity awards because restricted units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” In addition, we believe the award of restricted units aligns the interests of the recipient with our unitholders because restricted units have upside and downside risk.
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Inergy Long Term Incentive Plan
Our general partner sponsors the Inergy Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for us. The plan is administered by the compensation committee of the general partner's board of directors.
Unit Options
The Inergy Long Term Incentive Plan currently permits, and our general partner has made, grants of options covering common units. Unit options will have an exercise price equal to the fair market value of the units on the date of grant. In general, unit options will become exercisable over a five-year period. In addition, the unit options will become exercisable upon a change of control of the general partner or us. Generally, unit options will expire after ten years.
Upon exercise of a unit option, our general partner will acquire common units in the open market, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. The general partner will be entitled to reimbursement by us for the difference between the cost incurred by the general partner in acquiring these common units and the proceeds received by the general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase and the general partner will pay us the proceeds it received from the optionee upon exercise of the unit options. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Restricted Units
The Inergy Long Term Incentive Plan currently permits, and our general partner has made, grants of restricted units. Restricted units are subject to a restricted period the terms of which are set forth in a restricted unit award agreement. In general, restricted units vest over a five-year period. The individual award agreement also sets forth the conditions under which the restricted units may become vested or forfeited, which may include, without limitation, the accelerated vesting upon the achievement of specified performance goals, or the forfeiture for failing to achieve specified performance goals and such other terms and conditions as the committee may establish. Unless otherwise specifically provided for in an award agreement, distributions are paid to the holder of the restricted units without restriction. Restricted units are designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Termination and Amendment
The general partner's board of directors in its discretion may terminate the Inergy Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. The general partner's board of directors also has the right to alter or amend Inergy Long Term Incentive Plan from time to time, including increasing the number of common units with respect to which awards may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Inergy Midstream Long Term Incentive Plan
NRGM GP, LLC sponsors the Inergy Midstream, L.P. Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for it. The plan is administered by the compensation committee of NRGM GP, LLC's board of directors.
Restricted Units
The Inergy Midstream, L.P. Long Term Incentive Plan currently permits, and its general partner has made, grants of restricted units. The restricted units granted to our named executive officers are reported in the equity tables below. Restricted units are subject to a restricted period the terms of which are set forth in a restricted unit award agreement. In general, restricted units vest over a five-year period. The individual award agreement also sets forth the conditions under which the restricted units may become vested or forfeited, which may include, without limitation, the accelerated vesting upon the achievement of specified performance goals, or the forfeiture for failing to achieve specified performance goals and such other terms and conditions as the committee may establish. Unless otherwise specifically provided for in an award agreement, distributions are paid to the holder of the restricted units without restriction. Restricted units are designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
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Termination and Amendment
NRGM GP, LLC's board of directors in its discretion may terminate the Inergy Midstream Long Term Incentive Plan at any time with respect to any common units for which a grant has not yet been made. NRGM GP LLC's board of directors also has the right to alter or amend Inergy Midstream Long Term Incentive Plan from time to time, including increasing the number of common units with respect to which awards may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Other Compensation Related Matters
Retirement and Health Benefits
We offer a variety of health and welfare and retirement programs to all eligible employees. The named executive officers are eligible for the same programs on the same basis as other employees. We maintain a 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantages basis. We match 50% of the first 6% of the deferral to the retirement plan (not to exceed the maximum amount permitted by law) made by eligible participants. Our executive officers are also eligible to participate in additional employee benefits available to our other employees.
Perquisites and Other Compensation
We do not provide perquisites or other personal benefits to any of the named executive officers.
Severance and Change of Control Benefits
We maintain employment agreements with all our named executive officers to ensure they will perform their roles for an extended period of time and not compete with us upon termination of employment. These agreements are described in more detail elsewhere in this annual report. Please read “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table - Employment Agreements.” These agreements do not provide any form of severance payment upon a change in control. However, the agreements do provide for continued salary payments following termination of employment without cause (as defined in the employment agreements). Thus, the continued salary provisions only become operative in the event of a change in control if such change in control is accompanied by an involuntary change in employment status (such as the termination of employment). We believe this arrangement is appropriate because it provides assurance to the executive, but does not offer a windfall to the executive when there has been no real change in employment status. In addition, the Inergy Long Term Incentive Plan provides for accelerated vesting for outstanding awards triggered upon a change of control.
Tax Deductibility of Compensation
With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Thus the compensation that we pay to our employees is not subject to the deduction limitations under Section 162(m) of the Code.
Compensation Committee Report
We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended September 30, 2012.
Warren H. Gfeller
Arthur B. Krause
Members of the Compensation Committee
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Summary Compensation Table for the Fiscal Year Ended September 30, 2012
The following table sets forth the cash and non-cash compensation earned for the years ended September 30, 2012, September 30, 2011 and September 30, 2010, by each person who served as the Chief Executive Officer, Chief Financial Officer and the three other highest paid executive officers (the “named executive officers”) during fiscal 2012.
Name and Principal Position | Fiscal Year | Salary ($) | Bonus ($) | Stock Awards ($)(4) | Option Awards ($) | Non-Equity Incentive Plan Compensation ($) | All Other Compensation ($)(6) | Total ($) | |||||||||||||||
John. J. Sherman | 2012 | 400,000 | — | — | — | — | 11,692 | 411,692 | |||||||||||||||
Chief Executive Officer | 2011 | 393,653 | — | — | — | — | 11,319 | 404,972 | |||||||||||||||
2010 | 350,000 | — | — | — | — | 9,828 | 359,828 | ||||||||||||||||
R. Brooks Sherman, Jr.(1) | 2012 | 278,365 | 500,000 | 1,085,000 | (5) | — | — | 7,736 | 1,871,101 | ||||||||||||||
President | 2011 | 225,000 | — | — | — | — | 6,516 | 231,516 | |||||||||||||||
2010 | 225,000 | — | 5,669,950 | — | — | 7,807 | 5,902,757 | ||||||||||||||||
Michael J. Campbell(2) | |||||||||||||||||||||||
Senior Vice President— Chief Financial Officer | 2012 | 175,000 | 200,000 | 434,000 | (5) | — | — | 6,750 | 815,750 | ||||||||||||||
William C. Gautreaux | |||||||||||||||||||||||
President— Inergy Services | 2012 | 235,577 | 300,000 | 651,000 | — | — | 6,356 | 1,192,933 | |||||||||||||||
William R. Moler(3) | 2012 | 235,576 | — | 868,000 | (5) | — | — | 7,789 | 1,111,365 | ||||||||||||||
Former Senior Vice President— Natural Gas Midstream Operations | 2011 | 200,000 | — | — | — | — | 6,702 | 206,702 | |||||||||||||||
2010 | 200,000 | — | 3,254,625 | — | — | 8,160 | 3,462,785 | ||||||||||||||||
Laura L. Ozenberger | 2012 | 250,000 | 250,000 | 868,000 | (5) | — | — | 5,577 | 1,373,577 | ||||||||||||||
Senior Vice President— General Counsel and Secretary | 2011 | 235,385 | — | 3,264,800 | — | — | 7,842 | 3,508,027 | |||||||||||||||
2010 | 200,000 | 200,000 | — | — | — | 7,500 | 407,500 | ||||||||||||||||
(1) | R. Brooks Sherman, Jr. previously served as our Executive Vice President, since September 2007, and Chief Financial Officer, since March 2001, until he was named as President on September 27, 2012. |
(2) | Michael J. Campbell previously served as our Vice President and Treasurer since May 2005 until he was named as Senior Vice President and Chief Financial Officer on September 27, 2012. |
(3) | William R. Moler resigned as the Senior Vice President - Natural Gas Midstream Operations, effective as of October 5, 2012 . |
(4) The material terms of our outstanding LTIP awards to our executive officers are described in “Compensation Discussion and Analysis - Long-Term Incentive Plans.” Equity award amounts reflect the aggregate grant date fair value of unit awards granted during the periods presented.
(5) | As discussed in the “Compensation Discussion and Analysis” on May 2, 2012, R. Brooks Sherman, Jr. was awarded 50,000 Inergy Midstream, L.P restricted units, Michael J. Campbell was awarded 20,000 Inergy Midstream, L.P. restricted units, William C. Gautreaux was awarded 30,000 Inergy Midstream, L.P. restricted units and Laura L. Ozenberger and William R. Moler were each awarded 40,000 Inergy Midstream, L.P. restricted units. These awards vests in 25%, 25%, 50% annual installments beginning three years from the grant date. Mr. Moler forfeited his restricted units upon his resignation. |
(6) Represents matching contributions to the partnership's 401(k) Plan and Employee Unit Purchase Plan for each named executive officer. The partnership does not provide perquisites and other personal benefits.
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Grants of Plan Based Awards Table for the Fiscal Year Ended September 30, 2012
The following table provides information concerning each grant of an award made to our named executive officers in the last completed fiscal year under any plan, including awards that have been transferred.
Estimated Future Payouts Under Incentive Plan Awards | |||||||||||||||
Name | Threshold ($) | Target ($) | Maximum ($)(1) | All Other Stock Awards(#)(2) | Grant Date Fair Value of Stock and Option Awards ($) | ||||||||||
John J. Sherman | — | 400,000 | 400,000 | — | — | ||||||||||
R. Brooks Sherman, Jr. | — | 365,000 | 365,000 | 50,000 | 1,085,000 | ||||||||||
Michael J. Campbell | — | 250,000 | 250,000 | 20,000 | 434,000 | ||||||||||
William C. Gautreaux | — | 250,000 | 250,000 | 30,000 | 651,000 | ||||||||||
William R. Moler(3) | — | — | — | 40,000 | 868,000 | ||||||||||
Laura L. Ozenberger | — | 250,000 | 250,000 | 40,000 | 868,000 | ||||||||||
(1) | The amounts in these columns reflect the “Target” and “Maximum” bonus award amounts for our named executive officers with respect to cash bonuses awarded pursuant to each named executive officer's employment agreement. The “Maximum” amount may be increased by the discretion of the Compensation Committee as described above in the “Compensation Discussion and Analysis -Incentive Awards.” |
(2) | Amounts in this column reflect restricted unit award grants made on May 2, 2012, whereby R. Brooks Sherman, Jr. was awarded 50,000 Inergy Midstream, L.P. restricted units, Michael J. Campbell was awarded 20,000 Inergy Midstream, L.P. restricted units, William C. Gautreaux was awarded 30,000 Inergy Midstream, L.P. restricted units and Laura L. Ozenberger and William R. Moler were each awarded 40,000 Inergy Midstream, L.P. restricted units. The material terms of our 2012 restricted unit awards to our named executive officers are described in the narrative disclosure following the “Grants of Plan-Based Awards” table. |
(3) | Mr. Moler forfeited all of his outstanding equity awards on October 5, 2012 in connection with his resignation. |
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
A discussion of fiscal 2012 salaries and bonuses is included above in “Compensation Discussion and Analysis.” The following is a discussion of other material factors necessary to an understanding of the information disclosed in the Summary Compensation Table.
Employment Agreements
The following named executive officers have entered into employment agreements with our company:
• | John J. Sherman, Chief Executive Officer; |
• | R. Brooks Sherman, Jr., President; |
• | Michael J. Campbell, Senior Vice President - Chief Financial Officer; |
• | William C. Gautreaux, President - Inergy Services; |
• | Laura L. Ozenberger, Senior Vice President - General Counsel and Secretary. |
Prior to his resignation on October 5, 2012, we also maintained an employment agreement with William R. Moler. The following is a summary of the material provisions of these employment agreements, each of which is incorporated by reference herein as an exhibit to this report.
All of these employment agreements are substantially similar, with certain exceptions as set forth below. The employment agreements are for terms of five years. During the fiscal year, the annual salaries for these individuals are as follows:
• | John J. Sherman - $400,000 |
• | R. Brooks Sherman, Jr. - $300,000 (increased to $365,000 effective November 1, 2012) |
• | Michael J. Campbell - $175,000 (increased to $250,000 effective October 1, 2012) |
• | William C. Gautreaux - $250,000 |
• | Laura L. Ozenberger - $250,000 |
These employees are reimbursed for all expenses in accordance with the general partner's policies. They are also eligible for fringe benefits normally provided to other employees.
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All of the individuals are eligible for non-equity incentive compensation bonuses upon meeting certain established criteria for each year during the term of his or her employment.
Generally, unless waived by the general partner, in order for any of these individuals to receive any benefits under (i) the Inergy Long Term Incentive Plan, Inergy Midstream L.P. Long Term Incentive Plan, or (ii) the non-equity incentive compensation bonus, the individual must have been continuously employed by the general partner or one of our affiliates from the date of his or her employment agreement up to the date for determining eligibility to receive such amounts.
Each employment agreement contains confidentiality and noncompetition provisions. Also, each employment agreement contains a disclosure and assignment of inventions clause that requires the employee to disclose the existence of any invention and assign such employee's right in such invention to the general partner.
With respect to each of the named executive officers, in the event such person's employment is terminated without cause, we will be required to continue making payments to such person for the remainder of the term of such person's employment agreement.
Outstanding Equity Awards at Fiscal Year-End Table
The following table summarizes the options and restricted units outstanding as of September 30, 2012, for the named executive officers. The table includes unit options and restricted units of Inergy, L.P. (NYSE: NRGY) granted under the Inergy Long Term Incentive Plan and restricted units of Inergy Midstream, L.P. (NYSE: NRGM) granted under the Inergy Midstream, L.P. Long Term Incentive Plan.
OPTION AWARDS | UNIT AWARDS | ||||||||||||||||
Name | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options (#) Unexercisable | Option Exercise Price($) | Option Expiration Date | Number of Units That Have Not Vested (#) | Market Value of Units That Have Not Vested ($)(3) | |||||||||||
John J. Sherman | — | — | — | — | — | — | |||||||||||
R. Brooks Sherman, Jr. | — | — | — | — | 222,475 (NRGY)(1) 50,000 (NRGM)(2) | 4,233,699 1,167,000 | |||||||||||
Michael J. Campbell | — | — | — | — | 30,325 (NRGY)(1) 20,000 (NRGM)(2) | 577,085 466,800 | |||||||||||
William C. Gautreaux | — | — | — | — | 128,875 (NRGY)(1)30,000 (NRGM)(2) | 2,452,491 700,200 | |||||||||||
William R. Moler(4) | — | — | — | — | 153,000 (NRGY)(1) 40,000 (NRGM)(2) | 2,911,590 933,600 | |||||||||||
Laura L. Ozenberger | 36,358 | — | 5.62 | 6/19/2015 | 108,875 (NRGY)(1) 40,000 (NRGM)(2) | 2,071,891 933,600 | |||||||||||
(1) | Mr. Brooks Sherman, Jr.'s restricted units vest as follows: 40,425 on October 1, 2012, 45,512 on February 1, 2013, 45, 513 on February 1, 2014, and 91,025 on February 1, 2015. Mr. Campbell's restricted units vest as follows: 3,000 on October 24, 2012, 10,000 on January 5, 2014, and 17,325 on February 1, 2015. Mr. Gautreaux's restricted units vest as follows: 28,875 on November 1, 2012, 25,000 on April 21, 2014, 25,000 on April 21, 2015 and 50,000 on April 21, 2016. Mr. Ozenberger's restricted units vest as follows: 28,875 on October 1, 2012, 20,000 on January 27, 2013, 20,000 on January 27, 2014, 20,000 on January 27, 2015, and 20,000 on January 27, 2016. |
(2) | These awards vests in 25%, 25%, 50% annual installments beginning three years from the grant date (May 2, 2011). |
(3) | Market value for NRGY units based on the NYSE closing price of $19.03 on September 28, 2012 and market value for NRGM units based on the NYSE closing price of $23.34 on September 28, 2012. We used the closing prices on September 28, 2012 rather than September 30, 2012 for this table due to the fact that September 30, 2012 was a Sunday and no trading occurred. |
(4) | Mr. Moler forfeited all of his outstanding equity awards on October 5, 2012 in connection with his resignation. |
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Option Exercises and Stock Vested Table
The following table provides information regarding option exercises and restricted unit vesting during the fiscal year ended September 30, 2012, for the named executive officers. Value realized on exercise or upon vesting was calculated by using the closing price of Inergy, L.P. units on the date that the award was exercised or was vested, as applicable.
Option Awards | |||||||||||
Name | Number of Units Acquired on Exercise (#) | Value Realized on Exercise ($) | Number of Units Acquired on Vesting (#)(1) | Value Realized on Vesting ($) | |||||||
John J. Sherman | — | — | — | — | |||||||
R. Brooks Sherman, Jr. | — | — | 20,212 | 505,704 | |||||||
Michael J. Campbell | 8,662 | 52,281 | 3,000 | 81,360 | |||||||
William C. Gautreaux | — | — | 14,437 | 414,486 | |||||||
William R. Moler | — | — | 14,437 | 361,214 | |||||||
Laura L. Ozenberger | — | — | 14,437 | 361,214 | |||||||
(1) | Units acquired represent common units of Inergy, L.P. No Inergy Midstream, L.P. restricted units vested fiscal 2012. |
Pension Benefits Table
We do not offer any pension benefits.
Nonqualified Deferred Compensation Table
We have no non-qualified deferred compensation plans.
Potential Payments upon a Change in Control or Termination
Employment Agreements
Under the employment agreements with our named executive officers, we may be required to pay certain amounts upon the employment termination of the named executive officer in certain circumstances. Upon the termination of employment of a named executive officer without cause, the employment agreements entered into between Inergy GP, LLC and each of the named executive officers provide for salary continuation at the rate in effect at termination of the employee through the remaining term of the employment agreement. Consequently, no severance is payable in the event of any termination (i) as a result of death, disability, or legal incompetence, (ii) as a result of Inergy GP, LLC ceasing to carry on its business without assigning the employment agreement, (iii) as a result of Inergy GP, LLC becoming bankrupt, (iv) for cause or (v) by the employee for any or no reason. For purposes of the employment agreements:
Cause will generally be determined to have occurred in the event the:
• | employee has failed to perform his or her duties as an employee of Inergy GP, LLC, to perform any obligation under the employment agreement or to observe and abide by Inergy GP, LLC's policies and decisions, provided that Inergy GP, LLC has given employee reasonable notice of that failure and employee is unsuccessful in correcting that failure or in preventing its reoccurrence; |
• | employee has refused to comply with specific directions of his/her supervisor or other superior, provided that such directions are consistent with the employee's position of employment; |
• | employee has engaged in misconduct that is injurious to Inergy GP, LLC or any subsidiary, parent or affiliate of Inergy GP, LLC; |
• | employee has been convicted of, or has entered a plea of nolo contendere to, any crime involving the theft or willful destruction of money or other property, any crime involving moral turpitude or fraud, or any crime constituting a felony; |
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• | employee has engaged in acts or omissions against Inergy GP, LLC or any subsidiary, parent or affiliate of Inergy GP, LLC constituting dishonesty, breach of fiduciary obligation, or intentional wrongdoing or misfeasance; or |
• | employee has used alcohol or drugs on the job, or has engaged in excessive absenteeism from the performance of his/her duties as Inergy GP, LLC's employee, other than for reasons of illness. |
If a termination of a named executive officer by Inergy GP, LLC without cause were to have occurred as of September 30, 2012, our named executive officers would have been entitled to the following payments. Each of the named executive officers would also continue to be subject to the non-competition provisions of his or her employment agreement following such a termination.
• | John J. Sherman would have received $1,233,333, representing base salary for the remaining 37 months of the term of his employment agreement (payable bi-monthly in arrears). |
• | R. Brooks Sherman, Jr. would have received $700,000, representing base salary for the remaining 28 months of the term of his employment agreement (payable bi-monthly in arrears). |
• | Michael J. Campbell would have received $408,333, representing base salary for the remaining 28 months of the term of his employment agreement (payable bi-monthly in arrears). Effective as of October 1, 2012, Mr. Campbell entered into a new five year employment agreement. |
• | William C. Gautreaux would have received $400,000, representing two years base salary. |
• | William R. Moler would have received $520,833 representing base salary for the remaining 25 months of the term of his employment agreement (payable bi-monthly in arrears). Mr. Moler resigned effective as of October 5, 2012. Mr. Moler received no compensation in connection with is resignation. |
• | Laura L. Ozenberger would have received $812,500 representing base salary for the remaining 39 months of the term of her employment agreement (payable bi-monthly in arrears). |
Long Term Incentive Plans
Upon a change in control, all restricted units granted under the Inergy Long Term Incentive Plan and Inergy Midstream, L.P. Long Term Incentive Plan will automatically vest and become payable or exercisable, as the case may be, in full and any restricted periods or performance criteria will terminate or be deemed to have been achieved at the maximum level. There are no unvested unit options held by any of the named executive officers. For purposes of the Inergy Long Term Incentive Plan, a “change in control” means, and shall be deemed to have occurred upon one of the following events: (i) any sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Inergy Partners, LLC or Inergy, L.P. to any person or its affiliates, other than Inergy GP, LLC, the Partnership or any of their affiliates, or (ii) any merger, reorganization, consolidation or other transaction pursuant to which more than 50% of the combined voting power of the equity interests in Inergy GP, LLC or Inergy Partners, LLC ceases to be controlled by Inergy Holdings, L.P. For purposes of the Inergy Midstream, L.P. Long Term Incentive Plan a “change in control” means, and shall be deemed to have occurred upon one of the following events: (i) any sale, lease, exchange or other transfer (in one or a series of related transactions) of all or substantially all of the assets of the Inergy Midstream, L.P. to any person or its affiliates, other than a qualifying owner, NRGM GP, or any of their affiliates, or (ii) any merger, reorganization, consolidation or other transaction pursuant to which more than 50% of the combined voting power of the equity interests in NRGM GP, LLC ceases to be controlled by a qualifying owner or its affiliates.
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If a change in control were to have occurred as of September 30, 2012, all unvested restricted units held by the named executive officers under the Inergy Long Term Incentive Plan would have automatically vested and become exercisable, as follows:
Name | Restricted Units under the Inergy Long Term Incentive Plan (#) | Restricted Units under the Inergy Midstream Long Term Incentive Plan (#) | Total ($)(1) | |||||
John J. Sherman | — | — | — | |||||
R. Brooks Sherman, Jr. | 222,574 | 50,000 | 5,400,699 | |||||
Michael J. Campbell | 30,325 | 20,000 | 1,043,855 | |||||
William C. Gautreaux | 128,875 | 30,000 | 3,152,691 | |||||
William R. Moler(2) | 153,000 | 40,000 | 3,845,190 | |||||
Laura L. Ozenberger | 108,875 | 40,000 | 3,005,491 | |||||
(1) | The amounts included in the “Total” column are calculated by multiplying the number of NRGY restricted units by the closing per unit price of NRGY common units on September 28, 2012 ($19.03) and the number of NRGM restricted units by the closing per unit price of an NRGM common unit on September 28, 2012 ($23.34). |
(2) | Mr. Moler forfeited all of his equity awards on October 5, 2012 in connection with his resignation. |
Director Compensation Table for the Fiscal Year Ended September 30, 2012
The following table sets forth the cash and non-cash compensation for the year ended September 30, 2012, by each person who served as a non-employee director of our general partner Inergy GP, LLC.
Name | Fees Earned or Paid in Cash ($) | Unit Awards ($)(2) | Option Awards ($) | Total ($) | |||||||
Warren H. Gfeller | 59,500 | 49,994 | — | 109,494 | |||||||
Arthur B. Krause | 67,500 | 49,994 | — | 117,494 | |||||||
Robert D. Taylor | 66,500 | 49,994 | — | 116,494 | |||||||
Richard T. O’Brien(1) | 45,000 | 49,994 | — | 94,994 | |||||||
(1) | Richard T. O'Brien resigned from the board effective August 2, 2012 and forfeited all of his outstanding restricted units. |
(2) | On April 1, 2012, Messrs. Gfeller, Krause, Taylor and O'Brien were each awarded 3,054 Inergy, L.P. restricted units. Equity award amounts reflect the aggregate grant date fair value of unit awards granted during the period presented. As of September 30, 2012, Mr. Gfeller and Mr. Krause each held 4,420 restricted units and Mr. Taylor held 4,103 restricted units. |
Compensation of Directors
Officers of our general partner who also serve as directors will not receive additional compensation. Each director receives cash compensation of $40,000 per year for attending our regularly scheduled quarterly board meetings. Each non-employee director receives $1,000 for each special meeting of the board of directors attended and $1,000 per compensation or audit committee meeting attended. The chairman of the audit committee receives an annual fee of $10,000 per year and the chairman of the compensation committee receives an annual fee of $2,000 per year. Furthermore, each non-employee director receives an annual grant of restricted units under the long-term incentive plan equal to $50,000 in value. In April 2012, Messrs. Gfeller, Krause, Taylor and O'Brien each received 3,054 restricted units under the Inergy Long Term Incentive Plan. These units vest ratably over three years beginning one year from the grant date. Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified for actions associated with being a director to the extent permitted under Delaware law.
Compensation Committee Interlocks and Insider Participation
The compensation committee of the board of directors of our general partner oversees the compensation of our executive officers. Warren H. Gfeller and Arthur B. Krause serve as the members of the compensation committee, and neither of them was an officer or employee of our company or any of its subsidiaries during fiscal 2012.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth certain information as of November 19, 2012, regarding the beneficial ownership of our common units by:
• | each person who then beneficially owned more than 5% of such units then outstanding; |
• | each of the named executive officers of our general partner; |
• | each of the directors of our general partner; and |
• | all of the directors and executive officers of our general partner as a group. |
All information with respect to beneficial ownership has been furnished by the respective directors, executive officers or 5% or more unitholders, as the case may be.
Name of Beneficial Owner(1) | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | |||
John J. Sherman | 19,092,255 | 15.2 | % | ||
William C. Gautreaux | 2,099,316 | 1.7 | |||
R. Brooks Sherman, Jr. | 919,767 | * | |||
William R. Moler | 34,882 | * | |||
Laura L. Ozenberger | 141,356 | * | |||
Warren H. Gfeller | 118,116 | * | |||
Arthur B. Krause | 113,506 | * | |||
Robert D. Taylor | 21,223 | * | |||
Michael Campbell | 59,104 | * | |||
All directors and executive officers as a group (11 persons) | 25,066,247 | 20.0 | % | ||
* | Less than 1% |
(1) | Unless otherwise indicated, the address of each person listed above is: Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112. All persons listed have sole voting power and investment power with respect to their units unless otherwise indicated. |
We refer you to Item 5 of this report for certain information regarding securities authorized for issuance under equity compensation plans.
Item 13. Certain Relationships, Related Transactions and Director Independence.
For a discussion of director independence, see Item 10 "Directors, Executive Officers and Corporate Governance."
Transactions with Related Persons
Omnibus Agreement
We have entered into an omnibus agreement with our general partner, Inergy Midstream and its general partner that governs certain aspects of our relationship with them, including:
• | the provision by us to Inergy Midstream of certain administrative services and Inergy Midstream's agreement to reimburse us for such services; |
• | the provision by us of such employees as may be necessary to operate and manage Inergy Midstream's business, and Inergy Midstream's agreement to reimburse us for the expenses associated with such employees; |
• | certain indemnification obligations; |
• | Inergy Midstream's use of the name “Inergy” and related marks; and |
• | our right to review and first option with respect to business opportunities. |
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Our indemnification obligations to Inergy Midstream include certain liabilities relating to:
• | for three years after Inergy Midstream's initial public offering (IPO), certain environmental liabilities attributable to the ownership and operation of Inergy Midstream's assets prior to the Inergy Midstream IPO, including (i) any violation or correction of a violation of environmental laws associated with Inergy Midstream's assets, where a correction of violation would include assessment, investigation, monitoring, remediation, or other similar action and (ii) any event, omission or condition associated with the ownership or operation of Inergy Midstream's assets (including the presence or release of hazardous materials), including (a) the cost and expense of any assessment, investigation, monitoring, remediation or other similar action, (b) the cost and expense of the preparation and implementation of any closure activity or remedial or corrective action required under environmental laws, and (c) the cost and expense of any environmental or toxic tort litigation; |
• | environmental liabilities attributable with Inergy Midstream's prior ownership and operation of Tres Palacios Gas Storage LLC; |
• | the ownership and operation of Inergy Midstream's assets prior to its IPO; |
provided, that (i) the aggregate amount payable to us pursuant to the first bullet point above will not exceed $15 million and (ii) amounts are only payable to us pursuant to the first and second bullet points above after liabilities relating to the first and second bullet points have exceeded $100,000 and then only for such amounts in excess of $100,000;
• | until the first day after the applicable statute of limitations, any of Inergy Midstream's federal, state and local income tax liabilities attributable to the ownership and operation of Inergy Midstream's assets prior to the Inergy Midstream IPO; |
• | for three years after the closing of the Inergy Midstream IPO, the failure to have all necessary consents and governmental permits where such failure renders Inergy Midstream unable to use and operate its assets in substantially the same manner in which they were used and operated immediately prior to the Inergy Midstream IPO; and |
• | for three years after the closing of the Inergy Midstream IPO, Inergy Midstream's failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interest in and to the lands on which Inergy Midstream's assets are located and such failure prevents Inergy Midstream from using or operating its assets in substantially the same manner as they were used or operated immediately prior to the Inergy Midstream IPO. |
We will not be required to indemnify Inergy Midstream for any claims, losses or expenses or income taxes referred to above to the extent such were either (i) reserved for in Inergy Midstream's financial statements as of the closing of the Inergy Midstream IPO or (ii) Inergy Midstream recovers any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party.
Inergy Midstream's indemnification obligations to us, our general partner and to our affiliates (other than Inergy Midstream and its subsidiaries) include certain liabilities relating to:
• | certain environmental liabilities attributable to the ownership and operation of Inergy Midstream's assets, but only to the extent the violations, events, omissions or conditions giving rise to such covered environmental liabilities occur after the closing of the Inergy Midstream IPO; provided , that (i) our aggregate liability for such covered environmental liabilities will not exceed $15 million and (ii) amounts are only payable by us pursuant to this bullet point after liabilities relating to such covered environmental losses have exceeded $100,000 and then only for such amounts in excess of $100,000; and |
• | losses suffered or incurred by us by reason of or arising out of events and conditions associated with the operation of Inergy Midstream's assets that occur on or after the Inergy Midstream IPO (other than covered environmental losses, which are covered by the preceding bullet). |
With respect to the provision by us of certain administrative services and such management and operating services as may be necessary to manage and operate Inergy Midstream's business, the omnibus agreement addresses certain aspects of our relationship with Inergy Midstream, including:
• | the provision by us to Inergy Midstream of certain specified administrative services necessary to run Inergy Midstream's business, including the provision of such employees as may be necessary to operate and manage Inergy Midstream's business, and Inergy Midstream's agreement to reimburse us for all reasonable costs and expenses incurred in connection with such services; |
• | Inergy Midstream's agreement to reimburse us for all expenses we incurred as a result of Inergy Midstream becoming a publicly traded partnership; and |
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• | Inergy Midstream's agreement to reimburse us for all expenses that we incurred or payments we make on Inergy Midstream's behalf with respect to insurance coverage for our business. |
Under the omnibus agreement, we have granted and conveyed to Inergy Midstream a nontransferable, nonexclusive, royalty free right and license to use the name “Inergy” and any associated or related marks. Inergy Midstream's license to use the name “Inergy” will terminate upon the termination of the omnibus agreement. Under the omnibus agreement, we have the right to review and have the first option on any business opportunities that are presented to us or to Inergy Midstream.
Except for the indemnification provisions, the omnibus agreement may be terminated by us with 180 days' prior written notice if (i) NRGM GP, LLC is removed as Inergy Midstream's general partner under circumstances where “cause” does not exist and the common units held by us and our affiliates were not voted in favor of such removal; (ii) a change of control of Inergy Midstream occurs; or (iii) a change of control of us occurs. Except for the indemnification provisions, Inergy Midstream may terminate the omnibus agreement with 180 days' prior written notice if a change of control of Inergy occurs, a change of control of us occurs or Inergy Holdings GP, LLC (“Holdings GP”) acquires MGP GP, LLC as discussed below in “NRGM GP, LLC Change of Control Event.”
Tax Sharing Agreement
We have entered into a tax sharing agreement with Inergy Midstream pursuant to which Inergy Midstream will reimburse us for its share of state and local income and other taxes borne by us as a result of Inergy Midstream's income being included in a combined or consolidated tax return filed by us with respect to taxable periods including or beginning on the closing date of the Inergy Midstream IPO. The amount of any such reimbursement will be limited to the tax that Inergy Midstream (and its subsidiaries) would have paid had Inergy Midstream not been included in a combined group with us. We may use our tax attributes to cause our combined or consolidated group, of which Inergy Midstream may be a member for this purpose, to owe no tax. However, Inergy Midstream would nevertheless reimburse us for the tax Inergy Midstream would have owed had the attributes not been available or used for our benefit, even though we had no cash expense for that period.
NRGM GP, LLC Change of Control Event
In connection with the Inergy Midstream IPO, Inergy, L.P. and Holdings GP, the indirect owner of our general partner, entered into a membership interest purchase agreement under which, under certain circumstances, Holdings GP will be required to purchase from us, and we will be required to sell to Holdings GP, all of the membership interests in MGP GP, LLC, the entity that controls our general partner, for nominal consideration. MGP GP, LLC is a wholly owned subsidiary of Inergy, L.P. and the general partner of Inergy Midstream Holdings, L.P., which is the sole member of Inergy Midstream's general partner and direct holder of all of Inergy Midstream's IDRs. Under the agreement, Holdings GP is required to purchase MGP GP, LLC in the event that (i) a change of control of Inergy, L.P. occurs at a time when we are entitled to receive less than 50% of all cash distributed with respect to Inergy Midstream limited partner interests and IDRs or (ii) through dilution or a distribution to our common unitholders of our interests in Inergy Midstream, we are entitled to receive less than 25% of all cash distributed with respect to Inergy Midstream limited partner interests and IDRs. Either party may assign its rights and obligations under the agreement with the prior written consent of the other party.
The agreement will automatically terminate if prior to a purchase event in clauses (i) or (ii) above, (a) a change of control of us occurs prior to the time that we are entitled to receive less than 50% of all cash distributed with respect to Inergy Midstream limited partner interests and IDRs or (b) a change of control of Inergy Midstream occurs prior to the time that we are entitled to receive less than 25% of all cash distributed with respect to Inergy Midstream limited partner interests and IDRs.
Contribution Agreement
On December 21, 2011, in connection with the closing of the public offering of Inergy Midstream IPO, pursuant to the Contribution, Conveyance and Assumption Agreement by and among us, our general partner, Inergy Propane, LLC, MGP GP, LLC, MGP, Inergy Midstream's general partner and Inergy Midstream (the “Contribution Agreement”), we conveyed our initial limited partner interest in Inergy Midstream to Inergy Midstream, as a recapitalization of our interest in Inergy Midstream, in exchange for:
• | 55,925,000 common units representing a 75.2% limited partner interest in Inergy Midstream; |
• | the right to receive a distribution from Inergy Midstream of $80 million as reimbursement of pre-formation capital expenditures with respect to Inergy Midstream's assets; |
• | the issuance to MGP of all of the incentive distribution rights in Inergy Midstream; |
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• | Inergy Midstream's assumption of the Promissory Note; and |
• | the right to receive a distribution in the amount of $38,199,000 for the aggregate amount of cash contributed by the underwriters to Inergy Midstream with respect to the 2,400,000 common units of Inergy Midstream purchased by and issued to the underwriters in connection with their exercise in full of the over-allotment option. |
Pursuant to the Contribution Agreement, Inergy Midstream's general partner conveyed its initial general partner interest in Inergy Midstream to Inergy Midstream, as a recapitalization of its interest in Inergy Midstream, in exchange for a non-economic general partner interest in the Inergy Midstream.
As a contribution in capital to Inergy Midstream, Inergy also contributed to us all intercompany indebtedness that Inergy Midstream owed to Inergy Propane, LLC as of December 21, 2011, and such intercompany debt was canceled.
Other Transactions with Related Persons
Inergy Midstream provides firm storage services utilizing 100% of the operationally available storage capacity at Inergy Midstream's Bath storage facility to our subsidiary, Inergy Services, under a five-year contract entered into in March 2011. As of September 30, 2012 the annual storage fee is approximately $13.1 million. The terms and conditions of the storage contract are consistent with the terms and conditions of the storage leases that Inergy Services entered into with third parties. Inergy Midstream received total revenues from Inergy Services under this contract of $11.8 million for the fiscal year ended September 30, 2012.
In addition, Inergy Midstream will provide firm storage services utilizing 100% of the operationally available storage capacity at its proposed Watkins Glen NGL storage facility to Inergy Services under a five-year contract. As part of this development project, Inergy Services marketed this future storage capacity and entered into a five-year contract with an unaffiliated third party under which the anchor customer obtained the right to store two million barrels of propane and butane at the proposed facility. All revenue generated by Inergy Services from subleasing storage capacity to third parties at the Watkins Glen NGL storage facility will be paid to Inergy Midstream during the term of the affiliate contract. The other terms and conditions of the storage contract are consistent with the terms and conditions of the storage contracts that Inergy Services enters into with third parties, including the anchor customer.
As of September 30, 2011, Inergy Midstream had approximately $129.8 million of indebtedness outstanding to our former subsidiary, Inergy Propane, LLC (Inergy Propane), which was subject to interest during the period of construction of Inergy Midstream expansion projects. For the fiscal year ended September 30, 2011, the largest aggregate amount of principal outstanding and the amount of principal paid on indebtedness outstanding to Inergy Propane were $129.8 million and $77.1 million, respectively. For the fiscal year ended September 30, 2011, Inergy Midstream paid approximately $6.2 million of interest expense on the intercompany indebtedness. Inergy Midstream's outstanding intercompany indebtedness was subject to an interest rate of approximately 6.5% at September 30, 2011. This intercompany indebtedness was incurred to support our capital expansion and working capital needs. Upon completion of the Inergy Midstream IPO, this intercompany indebtedness was extinguished and treated as a capital contribution and part of our investment in Inergy Midstream.
Immediately prior to the closing of the Inergy Midstream IPO, we issued a $255 million unsecured promissory note to JPMorgan Chase Bank, N.A., which Inergy Midstream assumed immediately thereafter pursuant to an assignment and assumption agreement. Inergy Midstream assumed the promissory note as partial consideration to us in connection with the recapitalization of our interest in Inergy Midstream. Upon completion of the Inergy Midstream IPO, Inergy Midstream repaid the promissory note in full with the net proceeds from the IPO and borrowings of approximately $2.7 million under the Inergy Midstream revolving credit facility.
On November 25, 2011, in connection with the Inergy Midstream IPO, Inergy Midstream transferred US Salt to us. On May 14, 2012, Inergy Midstream re-acquired US Salt from us for a total purchase price of $192.5 million, including $182.5 million in cash and 473,707 common units of Inergy Midstream.
Review, Approval or Ratification of Transactions with Related Persons
Our Related Person Transactions Policy applies to any transaction since the beginning of our fiscal year (or currently proposed transaction) in which we or any of our subsidiaries was or is to be a participant, the amount involved exceeds $120,000 and any director, director nominee, executive officer, 5% or greater unitholder (or their immediate family members) had, has or will have a direct or indirect material interest. A transaction that would be covered by this policy would include, but not be limited
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to, any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships.
Under our Related Person Transactions Policy, related person transactions may be entered into or continue only if the transaction is deemed to be “fair and reasonable” to us, in accordance with the terms of our Partnership Agreement. Under our Partnership Agreement, transactions that represent a “conflict of interest” may be approved in one of three ways and, if approved in any of those ways, will be considered “fair and reasonable” to us and the holders of our common units. The three ways enumerated in our Related Person Transactions Policy for reaching this conclusion include:
(i) | approval by the Conflicts Committee of the Board (the “Conflicts Committee”) under Section 7.9 of the Partnership Agreement (“Special Approval”); |
(ii) | approval by our Chief Executive Officer applying the criteria specified in Section 7.9 of the Partnership Agreement if the transaction is in the normal course of the Partnership's business and is (a) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (b) fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership); and |
(iii) | approval by an independent committee of the Board (either the Audit Committee or a Special Committee) applying the criteria in Section 7.9 of the Partnership Agreement. |
Once a transaction is approved in any of these ways, it is “fair and reasonable” and accordingly deemed (i) approved by all of our partners and (ii) not to be a breach of any fiduciary duties of general partner.
Our general partner determines in its discretion which method of approval is required depending on the circumstances.
Under our Partnership Agreement, when determining whether a related person transaction is “fair and reasonable,” if our general partner elects to adopt a resolution or a course of action that has not received Special Approval, then our general partner may consider:
• | the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; |
• | any customary or accepted industry practices and any customary or historical dealings with a particular person; |
• | any applicable generally accepted accounting practices or principles; and |
• | such additional factors as the general partner or conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. |
A related person transaction that is approved by the conflicts committee is, as discussed in greater detail above, conclusively deemed to be fair and reasonable to us. Under our Partnership Agreement, the material facts known to our general partner or any of our affiliates regarding the transaction must be disclosed to the conflicts committee at the time the committee gives its approval. When approving a related party transaction, the conflicts committee considers all factors it considers relevant, reasonable or appropriate under the circumstances, including the relative interests of any party to the transaction, customary industry practices and generally accepted accounting principles.
Under our Partnership Agreement, in the absence of bad faith by the general partner, the resolution, action or terms so made, taken or provided by the general partner with respect to approval of the related party transaction will not constitute a breach of the Partnership Agreement or any standard of fiduciary duty.
Under our Related Person Transactions Policy, as well as under our Partnership Agreement, there is no obligation to take any particular conflict to the conflicts committee-empanelling that committee is entirely at the discretion of the general partner. In many ways, the decision to engage the conflicts committee can be analogized to the kinds of transactions for which a Delaware corporation might establish a special committee of independent directors. The general partner considers the specific facts and circumstances involved. Relevant facts would include:
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• | the nature and size of the transaction (e.g., transaction with a controlling unitholder, magnitude of consideration to be paid or received, impact of proposed transaction on the general partner and holders of common units); |
• | the related person's interest in the transaction; |
• | whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances; |
• | if applicable, the availability of other sources of comparable services or products; and |
• | the financial costs involved, including costs for separate financial, legal and possibly other advisors at our expense. |
When determining whether a related person transaction is in the normal course of our business and is (a) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (b) fair to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us), the general partner considers any facts and circumstances that it deems to be relevant, including:
• | the terms of the transaction, including the aggregate value; |
• | the business purpose of the transaction; |
• | the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; |
• | whether the terms of the transaction are comparable to the terms that would exist in a similar transaction with an unaffiliated third party; |
• | any customary or accepted industry practices; |
• | any applicable generally accepted accounting practices or principles; and |
• | such additional factors as the general partner or the conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. |
Item 14. Principal Accountant Fees and Services.
The following table presents fees billed for professional audit services rendered by Ernst & Young LLP for the audit of our and Inergy Midstream's annual financial statements and for other services for the years ended September 30, 2012 and 2011 (in millions):
Year Ended September 30, | |||||||
2012 | 2011 | ||||||
Audit fees(1) | $ | 3.3 | $ | 2.6 | |||
(1) | Audit fees consist of assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and financial statements of our subsidiaries. This category includes fees related to the review of our quarterly and other SEC filings and services related to internal control assessments. |
The audit committee of our general partner reviewed and approved all audit and non-audit services provided to us by Ernst & Young during fiscal 2012. For information regarding the audit committee’s pre-approval policies and procedures related to the engagement by us of an independent accountant, see our audit committee charter on our website at www.inergylp.com.
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PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) | Exhibits, Financial Statements and Financial Statement Schedules: |
1. | Financial Statements: |
See Index Page for Financial Statements located on page 94.
2. | Financial Statement Schedules: |
Schedule I: Parent Only Condensed Financial Statements located on page 136.
Schedule II: Valuation and Qualifying Accounts located on page 141.
Other financial statement schedules have been omitted because they are either not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.
3. | Exhibits: |
Exhibit Number | Description | |
*2.1 | Agreement and Plan of Merger, dated August 7, 2010, among Inergy, L.P., Inergy GP, LLC, Inergy Holdings, L.P., NRGP Limited Partner, LLC and NRGP MS, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on August 9, 2010) | |
*2.2 | First Amended and Restated Agreement and Plan of Merger, dated September 3, 2010, among Inergy, L.P., Inergy GP, LLC, Inergy Holdings, L.P., NRGP Limited Partner, LLC and NRGP MS, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on September 7, 2010) | |
*2.3 | Purchase and Sale Agreement, dated September 3, 2010, between TP Gas Holding LLC and Inergy Midstream, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on September 7, 2010) | |
*2.4 | Contribution Agreement dated April 25, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed April 26, 2012) | |
*2.5 | Amendment Contribution Agreement dated July 6 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed June 15, 2012) | |
*2.6 | Second Amendment Contribution Agreement dated June 15, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed July 6, 2012) | |
*2.7 | Third Amendment Contribution Agreement dated July 19, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed July 19, 2012) | |
*3.1 | Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001) | |
*3.1 A | Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q filed on May 12, 2003) | |
*3.2 | Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q filed on February 13, 2004) | |
*3.2 A | Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Inergy L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q filed on May 14, 2004) | |
*3.2 B | Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on January 24, 2005) | |
90
Exhibit Number | Description | |
*3.2 C | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K/A filed on August 17, 2005) | |
*3.2 D | Third Amended and Restated Agreement of Limited Partnership of Inergy, L.P., dated as of November 5, 2010 (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on November 5, 2010) | |
*3.5 | Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001) | |
*3.6 | Limited Liability Company Agreement of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.6 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001) | |
*4.1 | Specimen Unit Certificate for Common Units (incorporated herein by reference to Exhibit 4.3 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001) | |
*4.2 | Indenture, dated as of February 2, 2009, among Inergy, L.P., Inergy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on February 3, 2009) | |
*4.3 | First Supplemental Indenture and Amendment—Subsidiary Guarantee, dated as of November 5, 2010, to the Indenture, dated as of February 2, 2009 (incorporated herein by reference to Exhibit 10.4 to Inergy, L.P.’s Form 8-K filed on November 5, 2010) | |
*4.4 | Indenture, dated as of September 27, 2010, among Inergy, L.P., Inergy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on September 28, 2010) | |
*4.5 | First Supplemental Indenture and Amendment—Subsidiary Guarantee, dated as of November 5, 2010, to the Indenture, dated as of September 27, 2010 (incorporated herein by reference to Exhibit 10.5 to Inergy, L.P.’s Form 8-K filed on November 5, 2010) | |
*4.6 | Indenture, dated as of February 2, 2011, among Inergy, L.P., Inergy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to Inergy, L.P.’s Form 8-K filed on February 3, 2011) | |
*4.7 | Second Supplemental Indenture dated as of July 17, 2012, to the Indenture, dated as of September 27, 2010 (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.'s Form 8-K filed on July 19, 2012) | |
*4.8 | Second Supplemental Indenture dated as of July 17, 2012, to the Indenture, dated as of February 2, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.'s Form 8-K filed on July 19, 2012) | |
*4.9 | Third Supplemental Indenture dated as of August 1, 2012, to the Indenture, dated as of September 27, 2010 (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.'s Form 8-K filed on August 3, 2012) | |
*4.10 | Third Supplemental Indenture dated as of August 1, 2012, to the Indenture, dated as of February 2, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.'s Form 8-K filed on August 3, 2012) | |
*4.11 | Second Supplemental Indenture dated as of August 1, 2012, to the Indenture, dated as of February 2, 2009 (incorporated herein by reference to Exhibit 4.3 to Inergy, L.P.'s Form 8-K filed on August 3, 2012) | |
*10.1 | Employment Agreement dated as of November 24, 2010 between Inergy GP, LLC and John J. Sherman (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 10-K filed on November 29, 2010)**** | |
*10.2 | Second Amended and Restated Employment Agreement, dated as of February 1, 2010, between Inergy GP, LLC and Phillip L. Elbert (incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 10-Q filed on February 3, 2010)**** | |
91
Exhibit Number | Description | |
*10.3 | Employment Agreement, dated as of October 1, 2007, between Inergy GP, LLC and William R. Moler (incorporated herein by reference to Exhibit 10.7 to Inergy L.P.’s Form 10-K filed on December 1, 2008)**** | |
*10.3A | First Amendment to Employment Agreement, dated as of November 25, 2009, between Inergy GP, LLC and—William R. Moler (incorporated herein by reference to Exhibit 10.7A to Inergy L.P.’s Form 10-K filed on November 30, 2009) | |
*10.4 | Employment Agreement, dated as of January 27, 2011 between Inergy GP, LLC and Laura L. Ozenberger (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.'s Form 10-K filed on November 15, 2011) | |
*10.5 | Amended and Restated Employment Agreement, dated as of February 1, 2010, between Inergy GP, LLC and R. Brooks Sherman, Jr. (incorporated by reference to Exhibit 10.1 to Inergy, L.P.’s Form 10-Q filed on February 3, 2010)**** | |
*10.6 | Inergy Long Term Incentive Plan (as amended and restated on August 14, 2008) (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on August 18, 2008)**** | |
*10.7 | Form of Inergy, L.P.’s Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 10.11 to Inergy, L.P.’s Form 10-K filed on November 29, 2007)**** | |
*10.8 | Amended and Restated Inergy Unit Purchase Plan (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q filed on February 13, 2004)**** | |
*10.9 | Form of Inergy, L.P.’s Unit Option Grant Agreement (incorporated herein by reference to Exhibit 10.10 to Inergy, L.P.’s Form 8-K filed on November 29, 2010))**** | |
*10.10 | Summary of Non-Employee Director Compensation(incorporated herein by reference to Exhibit 10.11 to Inergy, L.P.’s Form 10-K filed on November 29, 2010)**** | |
*10.11 | Amended and Restated Credit Agreement dated as of February 2, 2011among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on February 3, 2011) | |
*10.12 | Amendment No. 1 to Amended and Restated Credit Agreement, dated as of July 28, 2011 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent(incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on August 1, 2011) | |
*10.13 | Consent and Amendment No. 2 dated as of December 21, 2011 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.'s Form 8-K filed on December 22, 2011) | |
*10.14 | Consent and Amendment No. 3 dated as of April 13, 2012 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.'s Form 8-K filed on April 19, 2012) | |
*10.15 | Consent and Amendment No. 4 dated as of July 26, 2012 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.'s Form 8-K filed on July 27, 2012) | |
*10.16 | Contribution, Conveyance and Assumption Agreement dated December 21, 2011, by and among Inergy GP, LLC, Inergy, L.P., Inergy Propane, LLC, MGP GP, LLC, Inergy Midstream Holdings, L.P., NRGM GP, LLC, and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.2 to Inergy L.P.'s Form 8-K filed on December 22, 2011) | |
*10.17 | Omnibus Agreement, dated December 21, 2011by and among Inergy GP, LLC, Inergy, L.P., NRGM GP, LLC and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.3 to Inergy L.P.'s Form 8-K filed on December 22, 2011) | |
*10.18 | Membership Interest Purchase Agreement dated December 21, 2011, by and among Inergy , L.P. and Inergy Holdings GP, LLC (incorporated by reference to Exhibit 10.4 to Inergy L.P.'s Form 8-K filed on December 22, 2011) | |
*10.19 | Support Agreement dated August 1, 2012, by and among Inergy , L.P., Suburban Propane Partners, L.P. and Suburban Energy Finance Corp. (incorporated by reference to Exhibit 10.1 to Inergy L.P.'s Form 8-K filed on August 2, 2012) | |
92
Exhibit Number | Description | |
**10.20 | Employment Agreement dated as of October 1, 2012, between Inergy GP, LLC and Michael J. Campbell**** | |
**10.21 | Employment Agreement dated as of April 21, 2011, between Inergy GP, LLC and William C. Gautreaux**** | |
**12.1 | Computation of ratio of earnings to fixed charges | |
*14.1 | Inergy’s Code of Business Ethics and Conduct (incorporated herein by reference to Exhibit 14.1 to Inergy, L.P.’s Form 8-K filed on December 23, 2003) | |
**21.1 | List of subsidiaries of Inergy, L.P. | |
**23.1 | Consent of Ernst & Young LLP | |
**31.1 | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended | |
**31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended | |
**32.1 | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
**32.2 | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
***101.INS | XBRL Instance Document | |
***101.SCH | XBRL Taxonomy Extension Schema Document | |
***101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |
***101.LAB | XBRL Taxonomy Extension Label Linkbase Document | |
***101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |
***101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | |
* | Previously filed |
** | Filed herewith |
*** | Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. |
**** | Management contracts or compensatory plans or arrangements required to be identified by Item 15(a). |
(b) | Exhibits. |
See exhibits identified above under Item 15(a)3.
(c) | Financial Statement Schedules. |
See financial statement schedules identified above under Item 15(a)2.
93
Inergy, L.P. and Subsidiaries
Consolidated Financial Statements
September 30, 2012 and 2011 and each of the
Three Years in the Period Ended
September 30, 2012
Contents
Report of Independent Registered Public Accounting Firm | |
Report of Independent Registered Public Accounting Firm on Internal Controls | |
Audited Consolidated Financial Statements: | |
Consolidated Balance Sheets | |
Consolidated Statements of Operations | |
Consolidated Statements of Comprehensive Income | |
Consolidated Statements of Partners’ Capital | |
Consolidated Statements of Cash Flows | |
Notes to Consolidated Financial Statements | |
94
Report of Independent Registered Public Accounting Firm
The Board of Directors of Inergy GP, LLC and Unitholders of Inergy, L.P.
We have audited the accompanying consolidated balance sheets of Inergy, L.P. and Subsidiaries (the Company) as of September 30, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for each of the three years in the period ended September 30, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inergy, L.P. and Subsidiaries at September 30, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended September 30, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions and our report dated November 20, 2012, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Kansas City, Missouri
November 20, 2012
95
Report of Independent Registered Public Accounting Firm
The Board of Directors and Unitholders of Inergy, L.P.
We have audited Inergy, L.P. and Subsidiaries’ internal control over financial reporting as of September 30, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Inergy, L.P. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of its fiscal 2012 acquisitions, which are included in the 2012 consolidated financial statements of Inergy, L.P. and Subsidiaries and constituted $22.3 million of total assets as of September 30, 2012, and $44.9 million of revenues for the year then ended. Our audit of internal control over financial reporting of Inergy, L.P. and Subsidiaries also did not include an evaluation of the internal control over financial reporting of those fiscal 2012 acquisitions.
In our opinion, Inergy, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2012, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated financial statements of Inergy, L.P. and Subsidiaries and our report dated November 20, 2012 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Kansas City, Missouri
November 20, 2012
96
Inergy, L.P. and Subsidiaries Consolidated Balance Sheets (in millions, except unit information) | |||||||
September 30, | |||||||
2012 | 2011 | ||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | — | $ | 11.5 | |||
Accounts receivable, less allowance for doubtful accounts of $0.4 million and $0.2 million at September 30, 2012 and September 30, 2011, respectively | 133.6 | 112.9 | |||||
Inventories (Note 4) | 87.1 | 155.1 | |||||
Assets from price risk management activities | 37.5 | 17.1 | |||||
Prepaid expenses and other current assets | 20.3 | 16.1 | |||||
Current assets held for sale (Note 5) | — | 115.2 | |||||
Total current assets | 278.5 | 427.9 | |||||
Property, plant and equipment (Note 4) | 2,160.7 | 1,857.8 | |||||
Less: accumulated depreciation | 450.2 | 322.8 | |||||
Property, plant and equipment, net | 1,710.5 | 1,535.0 | |||||
Intangible assets (Note 4): | |||||||
Customer accounts | 41.2 | 39.7 | |||||
Other intangible assets | 21.3 | 56.9 | |||||
62.5 | 96.6 | ||||||
Less: accumulated amortization | 21.2 | 29.0 | |||||
Intangible assets, net | 41.3 | 67.6 | |||||
Assets held for sale (Note 5) | — | 1,146.7 | |||||
Goodwill | 165.8 | 162.0 | |||||
Other assets | 11.5 | 1.7 | |||||
Total assets | $ | 2,207.6 | $ | 3,340.9 | |||
Liabilities and partners’ capital | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 120.8 | $ | 145.6 | |||
Accrued expenses | 93.9 | 72.1 | |||||
Liabilities from price risk management activities | 20.9 | 19.0 | |||||
Current portion of long-term debt (Note 8) | 3.4 | 3.2 | |||||
Liabilities held for sale (Note 5) | — | 82.1 | |||||
Total current liabilities | 239.0 | 322.0 | |||||
Long-term debt, less current portion (Note 8) | 739.8 | 1,833.4 | |||||
Other long-term liabilities | 23.4 | 19.3 | |||||
Deferred income taxes | 20.6 | 20.2 | |||||
Partners’ capital (Note 11): | |||||||
Limited partner unitholders (125,795,836 and 119,147,858 common units issued and outstanding at September 30, 2012 and September 30, 2011, respectively, and 5,882,105 and 12,165,499 Class B units issued and outstanding at September 30, 2012 and September 30, 2011, respectively) | 1,046.2 | 1,146.0 | |||||
Total Inergy, L.P. partners’ capital | 1,046.2 | 1,146.0 | |||||
Interest of non-controlling partners in subsidiaries | 138.6 | — | |||||
Total partners’ capital | 1,184.8 | 1,146.0 | |||||
Total liabilities and partners’ capital | $ | 2,207.6 | $ | 3,340.9 | |||
The accompanying notes are an integral part of these consolidated financial statements.
97
Inergy, L.P. and Subsidiaries Consolidated Statements of Operations (in millions, except unit and per unit data) | |||||||||||
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Revenue: | |||||||||||
Propane | $ | 1,289.0 | $ | 1,461.9 | $ | 1,272.4 | |||||
Other | 717.8 | 691.9 | 513.6 | ||||||||
2,006.8 | 2,153.8 | 1,786.0 | |||||||||
Cost of product sold (excluding depreciation and amortization as shown below): | |||||||||||
Propane | 974.5 | 1,044.0 | 862.9 | ||||||||
Other | 421.7 | 432.0 | 303.0 | ||||||||
1,396.2 | 1,476.0 | 1,165.9 | |||||||||
Expenses: | |||||||||||
Operating and administrative | 300.8 | 323.3 | 310.7 | ||||||||
Depreciation and amortization | 169.6 | 191.8 | 161.8 | ||||||||
Loss on disposal of assets | 5.7 | 8.2 | 11.5 | ||||||||
Operating income | 134.5 | 154.5 | 136.1 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | (83.6 | ) | (113.5 | ) | (91.5 | ) | |||||
Gain on disposal of retail propane operations (Note 5) | 589.5 | — | — | ||||||||
Loss on Suburban Propane Partners, L.P. units (Note 5) | (47.6 | ) | — | — | |||||||
Early extinguishment of debt (Note 8) | (26.6 | ) | (52.1 | ) | — | ||||||
Other income | 1.5 | 1.2 | 2.0 | ||||||||
Income (loss) before income taxes | 567.7 | (9.9 | ) | 46.6 | |||||||
Provision for income taxes | 1.8 | 0.7 | 0.2 | ||||||||
Net income (loss) | 565.9 | (10.6 | ) | 46.4 | |||||||
Net (income) loss attributable to non-controlling partners | (11.0 | ) | 28.2 | 15.4 | |||||||
Net income attributable to partners | $ | 554.9 | $ | 17.6 | $ | 61.8 | |||||
Partners’ interest information: | |||||||||||
Total limited partners’ interest in net income | $ | 554.9 | $ | 17.6 | $ | 61.8 | |||||
Net income per limited partner unit: | |||||||||||
Basic | $ | 4.39 | $ | 0.17 | $ | 1.73 | |||||
Diluted | $ | 4.22 | $ | 0.15 | $ | 1.29 | |||||
Weighted-average limited partners’ units outstanding (in thousands): | |||||||||||
Basic | 124,976 | 105,732 | 35,726 | ||||||||
Dilutive units | 6,613 | 11,952 | 12,276 | ||||||||
Diluted | 131,589 | 117,684 | 48,002 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
98
Inergy, L.P. and Subsidiaries Consolidated Statements of Comprehensive Income (in millions) | |||||||||||
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Net income (loss) | $ | 565.9 | $ | (10.6 | ) | $ | 46.4 | ||||
Change in unrealized fair value on cash flow hedges (Note 2) | (8.2 | ) | (11.1 | ) | (6.6 | ) | |||||
Comprehensive income (loss) | $ | 557.7 | $ | (21.7 | ) | $ | 39.8 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
99
Inergy, L.P. and Subsidiaries Consolidated Statements of Partners’ Capital (in millions) | |||||||||||
Common Unit Capital | Non-Controlling Partners | Total Partners’ Capital | |||||||||
Balance at September 30, 2009 | $ | 40.5 | $ | 731.5 | $ | 772.0 | |||||
Net proceeds from the issuance of common units | — | 602.7 | 602.7 | ||||||||
Net proceeds from common unit options exercised | 6.2 | 2.8 | 9.0 | ||||||||
Unit-based compensation charges | — | 4.8 | 4.8 | ||||||||
Acquisition of non-controlling interest | — | (18.3 | ) | (18.3 | ) | ||||||
Costs associated with the simplification of capital structure | (4.1 | ) | (2.9 | ) | (7.0 | ) | |||||
Retirement of common units | — | (0.1 | ) | (0.1 | ) | ||||||
Distributions | (77.6 | ) | (165.2 | ) | (242.8 | ) | |||||
Gain on issuance of units in subsidiary | 27.1 | (27.1 | ) | — | |||||||
Change in unrealized fair value on cash flow hedges | (0.6 | ) | (6.0 | ) | (6.6 | ) | |||||
Net income excluding gain on issuance of units in subsidiary | 61.8 | (15.4 | ) | 46.4 | |||||||
Balance at September 30, 2010 | 53.3 | 1,106.8 | 1,160.1 | ||||||||
Net proceeds from the issuance of common units | 311.4 | (0.2 | ) | 311.2 | |||||||
Net proceeds from common unit options exercised | 2.2 | 3.0 | 5.2 | ||||||||
Unit-based compensation charges | 4.4 | 1.4 | 5.8 | ||||||||
Acquisition of non-controlling interest | 1,032.9 | (1,032.9 | ) | — | |||||||
Costs associated with the simplification of capital structure | (0.7 | ) | (0.4 | ) | (1.1 | ) | |||||
Retirement of common units | (1.9 | ) | — | (1.9 | ) | ||||||
Distributions | (260.1 | ) | (51.5 | ) | (311.6 | ) | |||||
Change in unrealized fair value on cash flow hedges | (13.1 | ) | 2.0 | (11.1 | ) | ||||||
Net income (loss) | 17.6 | (28.2 | ) | (10.6 | ) | ||||||
Balance at September 30, 2011 | 1,146.0 | — | 1,146.0 | ||||||||
Net proceeds from the issuance of common units by Inergy Midstream, L.P. | — | 292.4 | 292.4 | ||||||||
Net proceeds from common unit options exercised | 1.3 | — | 1.3 | ||||||||
Certain costs relating to Inergy Midstream, L.P.'s initial public offering | (4.3 | ) | — | (4.3 | ) | ||||||
Unit-based compensation charges | 12.0 | 0.9 | 12.9 | ||||||||
Gain (loss) on issuance of Inergy Midstream, L.P. units | 133.8 | (133.8 | ) | — | |||||||
Gain (loss) associated with contribution of US Salt, LLC | 17.3 | (17.3 | ) | — | |||||||
Retirement of common units | (2.2 | ) | — | (2.2 | ) | ||||||
Distributions | (267.9 | ) | (14.6 | ) | (282.5 | ) | |||||
Distribution of Suburban Propane Partners, L.P. units (Note 11) | (536.5 | ) | — | (536.5 | ) | ||||||
Change in unrealized fair value on cash flow hedges | (8.2 | ) | — | (8.2 | ) | ||||||
Net income | 554.9 | 11.0 | 565.9 | ||||||||
Balance at September 30, 2012 | $ | 1,046.2 | $ | 138.6 | $ | 1,184.8 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
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Inergy, L.P. and Subsidiaries Consolidated Statements of Cash Flows (in millions) | |||||||||||
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Operating activities | |||||||||||
Net income (loss) | $ | 565.9 | $ | (10.6 | ) | $ | 46.4 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation and depletion | 148.0 | 154.8 | 126.5 | ||||||||
Amortization | 21.6 | 37.0 | 35.3 | ||||||||
Amortization of deferred financing costs, swap premium and net bond discount | 4.9 | 7.4 | 7.3 | ||||||||
Unit-based compensation charges | 12.9 | 5.8 | 4.8 | ||||||||
Provision for doubtful accounts | 2.1 | 3.7 | 2.8 | ||||||||
Loss on disposal of assets | 5.7 | 8.2 | 11.5 | ||||||||
Deferred income taxes | 0.4 | (0.5 | ) | (0.3 | ) | ||||||
Early extinguishment of debt | 10.0 | 12.7 | — | ||||||||
Gain on disposal of retail propane operations | (589.5 | ) | — | — | |||||||
Loss on Suburban Propane Partners, L.P. units | 47.6 | — | — | ||||||||
Changes in operating assets and liabilities, net of effects from acquisitions and dispositions: | |||||||||||
Accounts receivable | (1.3 | ) | (59.9 | ) | 1.9 | ||||||
Inventories | 85.7 | (75.4 | ) | (33.4 | ) | ||||||
Prepaid expenses and other current assets | (5.3 | ) | (1.2 | ) | 7.6 | ||||||
Other assets (liabilities) | (3.6 | ) | (1.9 | ) | 0.4 | ||||||
Accounts payable and accrued expenses | (29.3 | ) | 46.1 | (21.1 | ) | ||||||
Customer deposits | (10.2 | ) | (4.8 | ) | (5.8 | ) | |||||
Net assets/(liabilities) from price risk management activities | (26.6 | ) | (7.0 | ) | (10.3 | ) | |||||
Net cash provided by operating activities | 239.0 | 114.4 | 173.6 | ||||||||
Investing activities | |||||||||||
Acquisitions, net of cash acquired | (32.5 | ) | (824.5 | ) | (253.0 | ) | |||||
Purchases of property, plant and equipment | (268.7 | ) | (180.6 | ) | (92.3 | ) | |||||
Payments associated with the disposal of retail propane operations | (58.1 | ) | — | — | |||||||
Proceeds from sale of assets | 8.7 | 26.5 | 6.9 | ||||||||
Investment in bond offering escrow account | — | 588.0 | (588.0 | ) | |||||||
Net cash used in investing activities | (350.6 | ) | (390.6 | ) | (926.4 | ) | |||||
The accompanying notes are an integral part of these consolidated financial statements. | |||||||||||
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Inergy, L.P. and Subsidiaries Consolidated Statements of Cash Flows (continued) (in millions) | |||||||||||
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Financing activities | |||||||||||
Proceeds from the issuance of Inergy, L.P. long-term debt | $ | 1,159.2 | $ | 1,971.8 | $ | 1,555.7 | |||||
Proceeds from the issuance of Inergy Midstream, L.P. long-term debt | 509.9 | — | — | ||||||||
Principal payments on Inergy, L.P. long-term debt | (1,476.6 | ) | (1,824.1 | ) | (1,003.2 | ) | |||||
Principal payments on Inergy Midstream, L.P. long-term debt | (93.4 | ) | — | — | |||||||
Proceeds for the issuance of promissory note | 255.0 | — | — | ||||||||
Principal payment on promissory note | (255.0 | ) | — | — | |||||||
Distributions | (267.9 | ) | (260.1 | ) | (77.6 | ) | |||||
Distributions paid to non-controlling partners | (14.6 | ) | (51.5 | ) | (165.2 | ) | |||||
Acquisition of minority interest | — | — | (18.3 | ) | |||||||
Payments for deferred financing costs | (7.5 | ) | (20.5 | ) | (23.6 | ) | |||||
Costs associated with the simplification of capital structure | — | (1.1 | ) | (2.3 | ) | ||||||
Net proceeds from issuance of Inergy, L.P. common units | — | 311.2 | 602.7 | ||||||||
Net proceeds from issuance of Inergy Midstream, L.P. common units | 292.4 | — | — | ||||||||
Retirement of common units | (2.2 | ) | (1.9 | ) | (0.1 | ) | |||||
Net proceeds from Inergy, L..P. common unit options exercised | 1.3 | 5.2 | 9.0 | ||||||||
Proceeds from swap settlement | 0.8 | 14.3 | 8.4 | ||||||||
Other | (1.3 | ) | — | — | |||||||
Net cash provided by financing activities | 100.1 | 143.3 | 885.5 | ||||||||
Net increase (decrease) in cash | (11.5 | ) | (132.9 | ) | 132.7 | ||||||
Cash at beginning of period | 11.5 | 144.4 | 11.7 | ||||||||
Cash at end of period | $ | — | $ | 11.5 | $ | 144.4 | |||||
Supplemental disclosure of cash flow information | |||||||||||
Cash paid during the period for interest | $ | 107.3 | $ | 89.8 | $ | 84.0 | |||||
Cash paid during the year for income taxes | $ | 1.4 | $ | 0.5 | $ | 0.8 | |||||
Supplemental schedule of noncash investing and financing activities | |||||||||||
Change in the value of intangible assets and equity | $ | (3.0 | ) | $ | — | $ | — | ||||
Distribution of Suburban Propane Partners, L.P. units (Note 11) | $ | 536.5 | $ | — | $ | — | |||||
Exchange of senior debt (Note 1) | $ | 1,187.0 | $ | — | $ | — | |||||
Net change to property, plant and equipment through accounts payable and accrued expenses | $ | 23.8 | $ | 19.6 | $ | (6.9 | ) | ||||
Change in the fair value of interest rate swap liability and related long-term debt | $ | — | $ | 0.5 | $ | (5.6 | ) | ||||
Acquisitions, net of cash acquired: | |||||||||||
Current assets | $ | 5.2 | $ | 5.5 | $ | 27.4 | |||||
Property, plant and equipment | 17.8 | 501.5 | 81.3 | ||||||||
Contractual rights | — | 266.9 | — | ||||||||
Intangible assets | 8.3 | 9.7 | 146.6 | ||||||||
Goodwill (Note 3) | 4.0 | 53.8 | 49.9 | ||||||||
Other assets | 0.1 | 1.0 | 0.1 | ||||||||
Current liabilities | (0.1 | ) | (12.9 | ) | (44.1 | ) | |||||
Debt | (2.8 | ) | (1.0 | ) | (8.2 | ) | |||||
Total acquisitions, net of cash acquired | $ | 32.5 | $ | 824.5 | $ | 253.0 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements
Note 1. Partnership Organization and Basis of Presentation
Organization
The accompanying consolidated financial statements include the accounts of Inergy, L.P. (“Inergy” or "the Company") and its wholly owned subsidiaries, Inergy Partners, LLC (“Partners”), IPCH Acquisition Corp. (“IPCHA”), Inergy Finance Corp. and Inergy Operations, LLC and its wholly owned subsidiaries. The accompanying consolidated financial statements also include the accounts of Inergy's majority-owned subsidiary, Inergy Midstream, L.P. (“Inergy Midstream”), and its wholly-owned subsidiaries.
Contribution of Retail Propane Operations
On August 1, 2012, Inergy (NYSE:NRGY) closed on its definitive agreement and contributed its retail propane operations to Suburban Propane Partners, L.P. (“SPH”) in exchange for consideration of approximately $1.8 billion. Under the terms of the agreement, Inergy received approximately 14.2 million SPH common units; and SPH exchanged $1,187.0 million of Inergy's outstanding senior notes for approximately $1,000.0 million of new SPH senior notes and cash paid to noteholders tendering the exchange. In connection with the closing of this transaction, we entered into a support agreement with SPH pursuant to which we are obligated to provide contingent, residual support of approximately $497 million of aggregate principal amount of the 7.5% senior unsecured notes due 2018 of SPH and Suburban Energy Finance Corp. (collectively, the “SPH Issuers”) or any permitted refinancing thereof. Under the support agreement, in the event the SPH Issuers fail to pay any principal amount of the supported debt when due, we will pay directly to, or to the SPH Issuers for the benefit of, the holders of the Supported Debt (“Holders”) an amount up to the principal amount of the supported debt that the SPH Issuers have failed to pay. We have no obligation to make a payment under the support agreement with respect to any accrued and unpaid interest or any redemption premium or other costs, fees, expenses, penalties, charges or other amounts of any kind whatsoever that shall be due to noteholders by the SPH Issuers, whether on or related to the supported debt or otherwise. The support agreement terminates on the earlier of the date the supported debt is extinguished or on the maturity date of supported debt or any permitted refinancing thereof.
On September 14, 2012, Inergy distributed approximately 14.1 million of the SPH common units it received to Inergy unitholders of record on August 29, 2012. Unitholders received approximately 0.108 SPH common units for each Inergy limited partner unit outstanding on the record date.
Inergy Midstream
On November 14, 2011, Inergy Midstream, LLC converted into a Delaware limited partnership and changed its name to Inergy Midstream, L.P. (“Inergy Midstream”). Inergy Midstream converted into a limited partnership in connection with the initial public offering (“IPO”) of its common units representing limited partnership interests. Inergy Midstream was formed by Inergy to acquire, develop, own and operate midstream energy assets.
On November 25, 2011, Inergy Midstream assigned 100% of its membership interests in each of US Salt, LLC (“US Salt”) and Tres Palacios Gas Storage LLC ("Tres Palacios") to Inergy.
On December 21, 2011, Inergy Midstream completed its IPO. Inergy Midstream sold 16,000,000 common units to public investors and the underwriters exercised their option to purchase an additional 2,400,000 common units. Prior to this offering, there had been no public market for Inergy Midstream's common units. The Inergy Midstream common units began trading on the New York Stock Exchange on December 16, 2011 under the symbol “NRGM.” Upon completion of the offering, Inergy owned, directly or indirectly, an approximate 75.2% limited partner interest and all of the incentive distribution rights ("IDRs") in Inergy Midstream. The IDRs entitle Inergy to receive 50% of all Inergy Midstream's distributions in excess of the initial quarterly distribution of $0.37 per unit. Additionally, Inergy indirectly owns NRGM GP, LLC, the general partner of Inergy Midstream, which entitles the general partner to management but no economic rights in Inergy Midstream.
On May 14, 2012, Inergy contributed 100% of the membership interests in US Salt to Inergy Midstream (“US Salt Contribution”) for $182.5 million of cash and 473,707 Inergy Midstream common units issued directly to Inergy. The cash proceeds were used to repay outstanding borrowings under Inergy's revolving credit facility. Following the US Salt Contribution, Inergy owns approximately 56.4 million limited partner units of NRGM, representing an approximate 75% ownership interest. In connection with the US Salt Contribution, (i) US Salt's guarantee of Inergy's senior notes, as well as the
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
lien granted to the lenders of Inergy's credit agreement on US Salt's membership interest and substantially all of its assets, were released; and (ii) US Salt's membership interests and substantially all of its assets were pledged as collateral under the Inergy Midstream credit facility.
Inergy, as the initial holder of Inergy Midstream's IDRs, has the right under its partnership agreement to elect to relinquish the right to receive incentive distribution payments based on Inergy Midstream's quarterly distribution and to reset, at a higher level, the quarterly distribution amount (upon which the incentive distribution payments to Inergy would be set). If Inergy elects to reset the quarterly distribution, it will be entitled to receive a number of newly issued Inergy Midstream common units. The number of common units to be issued to Inergy will equal the number of common units that would have entitled the holder to the quarterly cash distribution in the prior quarter equal to the distribution to Inergy on the IDRs in such prior quarter.
NRGM GP, LLC Change of Control Event
In connection with the IPO, Inergy and Inergy Holdings GP, LLC (“Holdings GP”), the indirect owner of Inergy's general partner, entered into a membership interest purchase agreement under which, under certain circumstances, Holdings GP will be required to purchase from Inergy, and Inergy will be required to sell to Holdings GP, all of the membership interests in MGP GP, LLC, the entity that controls Inergy Midstream's general partner, for nominal consideration. MGP GP, LLC is a wholly owned subsidiary of Inergy and the general partner of Inergy Midstream Holdings, L.P., which is the sole member of Inergy Midstream's general partner and direct holder of all of its IDRs. Under the agreement, Holdings GP is required to purchase MGP GP, LLC in the event that (i) a change of control of Inergy occurs at a time when Inergy is entitled to receive less than 50% of all cash distributed with respect to Inergy Midstream's limited partner interests and IDRs or (ii) through dilution or a distribution to the Inergy common unitholders of Inergy's interests in Inergy Midstream, Inergy is entitled to receive less than 25% of all cash distributed with respect to Inergy Midstream's limited partner interests and IDRs.
Nature of Operations
Subsequent to the sale of Inergy's retail propane operations, the Company reorganized its operating and reporting segments. Inergy's financial statements now reflect two operating and reportable segments: NGL marketing, supply and logistics operations and storage and transportation operations. Inergy's NGL marketing, supply and logistics operations include marketing and supply of natural gas liquids ("NGLs") and marketing and price risk management services to other users, retailers and resellers of NGLs, NGL fractionation, logistics and transportation of NGLs and the results of the retail propane operations contributed to SPH on August 1, 2012. Inergy's NGL marketing, supply and logistics segment includes its West Coast fractionation facility, a fleet of 275 tractors and 452 transports and a team of experienced employees in the NGL business.
Inergy's storage and transportation operations include storage and transportation of natural gas and NGLs for third parties and the production and sale of salt products. Following the Inergy Midstream IPO and the US Salt Contribution, Inergy's storage and transportation assets include the Tres Palacios natural gas storage facility in Texas and an approximate 75% ownership interest in Inergy Midstream. Through Inergy's ownership interest in Inergy Midstream, Inergy has an investment in four natural gas storage facilities in New York (Stagecoach, Thomas Corners, Steuben and Seneca Lake), natural gas transportation assets in New York and Pennsylvania (the North-South Facilities, the MARC I Pipeline, and the East Pipeline) , an NGL storage facility in New York (Bath storage facility), and a solution-mining and salt production company in New York (US Salt).
Principles of Consolidation
All significant intercompany transactions and balances have been eliminated in consolidation.
On August 1, 2012, Inergy contributed its retail propane operations to SPH. ASC 205 requires that in order for a transaction to be considered discontinued operations, the gross cash flows related to the continuing involvement with the discontinued operations must be immaterial. The financial statements do not report the retail propane operations as discontinued as the involvement of Inergy with the retail propane operations subsequent to sale is expected to be material due to a propane supply arrangement between Inergy and SPH. The assets and liabilities associated with the retail propane operations have been classified as held for sale on the September 30, 2011 consolidated balance sheet. See Note 5 for a discussion of the amounts related to the assets and liabilities held for sale.
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Note 2. Summary of Significant Accounting Policies
Financial Instruments and Price Risk Management
Inergy utilizes certain derivative financial instruments to (i) manage its exposure to commodity price risk, specifically, the related change in the fair value of inventories, as well as the variability of cash flows related to forecasted transactions; (ii) ensure adequate physical supply of commodity will be available; and (iii) manage its exposure to interest rate risk associated with fixed and variable rate borrowings. Inergy records all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded either through current earnings or as other comprehensive income, depending on the type of transaction.
Inergy is party to certain commodity derivative financial instruments that are designated as hedges of selected inventory positions, and qualify as fair value hedges. Inergy is also periodically party to certain interest rate swap agreements designed to manage interest rate risk exposure. Inergy's overall objective for entering into fair value hedges is to manage its exposure to fluctuations in commodity prices and changes in the fair market value of its inventories and fixed rate borrowings. The commodity derivatives are recorded at fair value on the consolidated balance sheets as price risk management assets or liabilities and the related change in fair value is recorded to earnings in the current period as cost of product sold. The interest rate derivatives are recorded at fair value on the balance sheets in other assets or liabilities and the related change in fair value is recorded to earnings in the current period as interest expense.
Any ineffective portion of the fair value hedges is recognized as cost of product sold or interest expense in the current period. Inergy recognized a $0.5 million, $1.8 million and $0.4 million net gain in the years ended September 30, 2012, 2011 and 2010, respectively, related to the ineffective portion of its commodity fair value hedging instruments. In addition, for the years ended September 30, 2012 and 2011, Inergy recognized no gain, respectively, and for the year ended September 30, 2010, Inergy recognized a net loss of $0.1 million related to the portion of fair value hedging instruments that it excluded from its assessment of hedge effectiveness.
Inergy also enters into derivative financial instruments that qualify as cash flow hedges, which hedge the exposure of variability in expected future cash flows predominantly attributable to forecasted purchases to supply fixed price sale contracts and variable interest payments. These derivatives are recorded on the balance sheet at fair value as price risk management assets or liabilities. The effective portion of the gain or loss on these cash flow hedges is recorded in other comprehensive income in partner's capital and reclassified into earnings in the same period in which the hedge transaction affects earnings. In certain situations under the rules, the ineffective portion of the gain or loss is recognized as cost of product sold in the current period. Accumulated other comprehensive loss was $14.9 million and $6.7 million at September 30, 2012 and 2011, respectively. Included in accumulated other comprehensive loss at September 30, 2012 was a loss of $7.4 million attributable to commodity instruments and a loss of $7.5 million attributable to interest rate swaps. Approximately $6.9 million is expected to be reclassified to earnings from other comprehensive income over the next twelve months.
Inergy's policy is to offset fair value amounts of derivative instruments and cash collateral paid or received with the same counterparty under a master netting arrangement.
The cash flow impact of derivative financial instruments is reflected as cash flows from operating activities in the consolidated statements of cash flows.
Revenue Recognition
Sales of NGLs and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. Gas processing and fractionation fees are recognized upon delivery of the product. Revenues from storage and transportation contracts are recognized during the period in which the storage and transportation services are provided.
Expense Classification
Cost of product sold consists of tangible products sold, including NGLs and salt, as well as certain direct costs incurred in providing storage services. Operating and administrative expenses consist of all expenses incurred by Inergy other than those described above in cost of product sold and depreciation and amortization. Certain of Inergy's operating and administrative expenses and depreciation and amortization are incurred in the distribution of the product sales and storage sale but are not included in cost of product sold. These amounts were $196.7 million, $209.5 million and $176.3 million during the years ended September 30, 2012, 2011 and 2010, respectively.
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Credit Risk and Concentrations
Inergy generally extends unsecured credit to its NGL customers in the United States and Canada. In addition, Inergy collects margin payments from its customers to mitigate risk. Inergy's natural gas storage customers are primarily investment grade. Provisions for doubtful accounts receivable are based on specific identification and historical collection results and have generally been within management's expectations. Account balances are charged off against the reserve when it is anticipated that the receivable will not be collected. The balance is considered past due or delinquent based on contractual terms.
Inergy enters into netting agreements with certain NGL customers to mitigate the Company's credit risk. Realized gains and losses reflected in the Company's receivables and payables are reflected as a net balance to the extent a netting agreement is in place and the Company intends to settle on a net basis. Unrealized gains and losses reflected in the Company's assets and liabilities from price risk management activities are reflected on a net basis to the extent a netting agreement is in place.
Two suppliers, PBF Holding Corp. (22%) and BP Amoco Corp. (10%), accounted for 32% of propane purchases during the past fiscal year. No other single supplier accounted for more than 10% of propane purchases in the current year.
No single customer represented 10% or more of consolidated revenues. In addition, nearly all of Inergy's revenues are derived from sources within the United States, and all of its long-lived assets are located in the United States.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates.
Inventories
Inventories for NGL marketing, supply and logistics operations, which mainly consist of propane gas and other liquids, are stated at the lower of cost or market and are computed using the average cost method. These inventories are designated under a fair value hedge program and are consequently marked to market. Propane and other liquids inventories being hedged and carried at market value at September 30, 2012 and 2011, amount to $73.2 million and $147.7 million, respectively. Inventories for storage and transportation operations are stated at the lower of cost or market and are computed predominantly using the average cost method.
Shipping and Handling Costs
Shipping and handling costs are recorded as part of cost of product sold at the time product is shipped or delivered to the customer except as discussed in “Expense Classification.”
Property, Plant and Equipment
Property, plant and equipment are stated at historical cost less accumulated depreciation. Inergy capitalizes all construction-related direct labor and material costs as well as the cost of funds used during construction. Amounts capitalized for cost of funds used during construction amounted to $14.8 million, $16.2 million and $6.4 million for the years ended September 30, 2012, 2011 and 2010, respectively. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:
Years | |
Buildings and storage rights | 15 – 70 |
Office furniture and equipment | 3 – 7 |
Vehicles | 3 – 10 |
Plant equipment | 3 – 30 |
Base gas | 10 |
Salt deposits are depleted on a unit of production method.
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Inergy reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Inergy has not identified any long-lived assets in which the carrying amount exceeded the fair value at September 30, 2012.
Identifiable Intangible Assets
The Company has recorded certain identifiable intangible assets, including customer accounts, covenants not to compete and deferred financing costs. Customer accounts and covenants not to compete have arisen from acquisitions. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer's intent to do so.
Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:
Weighted-Average Life (years) | |
Customer accounts | 18.9 |
Covenants not to compete | 10.0 |
Deferred financing costs | 4.4 |
Estimated amortization, including amortization of deferred financing costs reported as interest expense, for the next five years ending September 30, is as follows (in millions):
Year Ending September 30, | |||
2013 | $ | 6.5 | |
2014 | 4.7 | ||
2015 | 4.4 | ||
2016 | 4.4 | ||
2017 | 2.8 | ||
Goodwill
Goodwill is recognized for various acquisitions as the excess of the cost of the acquisitions over the fair value of the related net assets at the date of acquisition. Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test.
In connection with the goodwill impairment evaluation, the Company identified five reporting units. The carrying value of each reporting unit is determined by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of the evaluation on a specific identification basis. To the extent a reporting unit’s carrying value exceeds its fair value, an indication exists that the reporting unit’s goodwill may be impaired and the second step of the impairment test must be performed. In the second step, the implied fair value of the goodwill is determined by allocating the fair value to all of its assets (recognized and unrecognized) and liabilities to its carrying amount.
Inergy has completed the impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2012.
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Income Taxes
Inergy is a publicly-traded master limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. Inergy Sales and Service, Inc. (“Services”), a subsidiary of Inergy, does not generate at least 90% of its gross income from qualifying sources, and as such, federal and state income taxes are provided on the taxable income of Services. The earnings of the Company and its limited liability subsidiaries are included in the Federal and state income tax returns of the individual members or partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes for Inergy have been included in the accompanying financial statements as income taxes due to the nature of the tax in those particular states. In addition, Federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities (IPCHA and Services). The Company is required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which differences are expected to reverse.
Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.
Sales Tax
Inergy accounts for the collection and remittance of all taxes on a net tax basis. As a result, these amounts are not reflected in the consolidated statements of operations.
Cash and Cash Equivalents
Inergy defines cash equivalents as all highly liquid investments with maturities of three months or less when purchased.
Computer Software Costs
Inergy includes costs associated with the acquisition of computer software in property, plant and equipment. Inergy amortizes computer software costs on a straight-line basis over expected periods of benefit, which generally are five years.
Fair Value
Cash and cash equivalents, accounts receivable (net of allowance for doubtful accounts) and payables are carried at cost, which approximates fair value due to their liquid and short-term nature. As of September 30, 2012, the estimated fair value of the Company's fixed-rate Senior Notes, based on available trading information, totaled $11.6 million compared with the aggregate principal amount at maturity of $11.5 million. The fair value of debt was determined based on market quotes from Bloomberg. This is considered a level 1 pricing source within the fair value hierarchy. At September 30, 2012, the Company's credit agreement (“Credit Agreement”) consists of a $550 million revolving loan facility (“Revolving Loan Facility”). The carrying value at September 30, 2012, of amounts outstanding under the Credit Agreement of $311.7 million approximate fair value due primarily to the floating interest rate associated with the Credit Agreement. At September 30, 2012, Inergy Midstream's $600 million revolving credit facility (“NRGM Credit Facility”) had amounts outstanding of $416.5 million, which approximated fair value due primarily to the floating interest rate associated with borrowings under the NRGM Credit Facility. See Note 8 for a discussion of the Company's debt.
Assets and liabilities from price risk management are carried at fair value as discussed in Note 7. At September 30, 2012, the estimated fair value of assets, on a net basis, from price risk management activities amounted to $37.5 million and liabilities, on a net basis, from price risk management amounted to $20.9 million.
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Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Comprehensive Income (Loss)
Comprehensive income includes net income and other comprehensive income, which is solely comprised of unrealized gains and losses on derivative financial instruments. Accumulated other comprehensive income (loss) consists of the following (in millions):
Accumulated Other Comprehensive Income (Loss) | |||
Balance at September 30, 2010 | $ | 4.4 | |
Other Comprehensive income(a) | (11.1 | ) | |
Balance at September 30, 2011 | (6.7 | ) | |
Other Comprehensive income(a) | (8.2 | ) | |
Balance at September 30, 2012 | $ | (14.9 | ) |
(a) | Other comprehensive income (loss) includes a reclassification of $(2.4) million and $4.9 million to net income during the years ended September 30, 2012 and 2011, respectively. |
Inergy records the effective portion of the unrealized gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.
Income Per Unit
Inergy calculates basic net income per limited partner unit by utilizing the two class method. Basic net income applicable to partners’ common interest is modified for the disproportionate ownership of Class B and certain restricted units in the undistributed earnings relative to their ownership of distributed earnings. This impact resulted in an decrease to basic net income per limited partner unit of $0.05 for the year ended September 30, 2012. Diluted net income per limited partner unit is computed by dividing net income by the weighted-average number of units outstanding and the effect of dilutive units granted under the Long Term Incentive Plan and the Class B units. Diluted net income per limited partner unit is not adjusted for the above described difference in Class B and certain restricted units’ share of undistributed and distributed earnings as the calculation assumes full conversion of the Class B and certain restricted units, which results in the most dilutive earnings per unit.
Asset Retirement Obligations
An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. The fair value of certain AROs could not be made as settlement dates (or range of dates) associated with these assets were not estimable.
Accounting for Unit-Based Compensation
Inergy sponsors a Long Term Incentive Plan and all share-based payments to employees, including grants of employee stock options, are recognized in the consolidated statements of operations based on their fair values.
The amount of compensation expense recorded by the Company during the years ended September 30, 2012, 2011 and 2010, was $17.9 million, $5.8 million and $10.9 million, respectively.
Segment Information
There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. In determining its reportable segments, Inergy examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 14 for disclosures related to Inergy’s NGL marketing, supply and logistics, and storage and transportation segments.
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Notes to Consolidated Financial Statements (Continued)
Recently Issued Accounting Pronouncements
In June 2011 the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). Under ASU 2011-05, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under both options, an entity will be required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. Furthermore, regardless of the presentation methodology elected, the entity will be required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05" ("ASU 2011-12") which deferred this requirement in order to allow the FASB more time to determine whether reclassification adjustments should be required to be presented on the face of the financial statements. The amendments contained in ASUs 2011-05 and 2011-12 do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments also do not affect how earnings per share is calculated or presented. The Company adopted ASUs 2011-05 and 2011-12 in the fourth quarter of the year ended September 30, 2012. The Company elected to present the total of comprehensive income in two separate but consecutive statements.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS" ("ASU 2011-04"). The amended guidance does not modify the requirements for when fair value measurements apply, rather it generally represents clarifications on how to measure and disclose fair value under ASC Topic 820 (Fair Value Measurements and Disclosures). Respective disclosure requirements are essentially the same. However, some of the specific amendments address the application of existing fair value measurement requirements and expand certain other disclosure requirements, particularly pertaining to level 3 fair value measurements. ASU 2011-04 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The Company adopted ASU 2011-04 in the first quarter of the year ended September 30, 2012. The adoption of this guidance did not have an impact on the Company's consolidated financial statements.
In January 2010, the FASB issued Accounting Standards Update No. 2010-06, "Improving Disclosures about Fair Value Measurements" ("ASU 2010-06"), which is included in the ASC Topic 820 (Fair Value Measurements and Disclosures). ASU 2010-06 requires new disclosures on the amount and reason for transfers in and out of level 1 and level 2 fair value measurements. ASU 2010-06 also requires disclosure of activities, including purchases, sales, issuances and settlements within the level 3 fair value measurements and clarifies existing disclosure requirements on levels of disaggregation and disclosures about inputs and valuation techniques. The Company has previously adopted the new disclosures for transfers in and out of level 1 and level 2. The new disclosures for level 3 were adopted on October 1, 2011, as disclosed in Note 7.
Note 3. Acquisitions
On January 13, 2012, Inergy completed the acquisition of substantially all the assets of Baker-Doucette, Inc. (d/b/a Woodstock Oil Company) and Rising Moon, LLC (d/b/a Woodstock Propane Company) (“Woodstock”), located in Bryant Pond, Maine. On February 13, 2012, Inergy completed the acquisition of all operating assets at the Aztec, New Mexico location of Alliance Propane, LLC (d/b/a Mesa Propane) (“Mesa Propane”). The operating results for the Woodstock and Mesa Propane acquisitions are included in the consolidated results of operations from the dates of acquisition through August 1, 2012, the date they were contributed to SPH.
On November 11, 2011, Inergy completed the acquisition of substantially all the assets of Papco, LLC / South Jersey Terminal, LLC (“Papco”), located in Bridgeton, New Jersey. On August 24, 2012, L&L Transportation, LLC (“L&L”) purchased substantially all of the operating assets of Werner Transportation Services, Inc. (“Werner”) located in Gainesville, Georgia. The operating results for the Papco and Werner acquisitions are included in the consolidated results of operations from the dates of acquisition and are included in the NGL marketing, supply and logistics segment.
The above described acquisitions are not material to the financial statements, individually or in the aggregate.
The purchase price allocations for the Papco and Werner acquisitions have been prepared on a preliminary basis pending final asset valuation and asset rationalization.
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Notes to Consolidated Financial Statements (Continued)
As a result of the Papco and Werner acquisitions, the Company acquired $3.8 million of goodwill and $7.1 million of intangible assets, consisting of the following (in millions):
Customer accounts | $ | 2.8 | |
Noncompetition agreements | 4.3 | ||
Total intangible assets | $ | 7.1 | |
The weighted-average amortization period of the above amortizable intangible assets acquired during the year ended September 30, 2012, is approximately twelve years.
Note 4. Certain Balance Sheet Information
Inventories
Inventories consisted of the following at September 30, 2012 and 2011, respectively (in millions):
September 30, | |||||||
2012 | 2011 | ||||||
NGLs | $ | 80.8 | $ | 149.8 | |||
Parts, supplies and other | 6.3 | 5.3 | |||||
Total inventory | $ | 87.1 | $ | 155.1 | |||
Property, Plant and Equipment
Property, plant and equipment consisted of the following at September 30, 2012 and 2011, respectively (in millions):
September 30, | |||||||
2012 | 2011 | ||||||
Plant equipment | $ | 619.3 | $ | 531.1 | |||
Buildings, land and storage rights | 895.2 | 840.7 | |||||
Vehicles | 44.1 | 25.0 | |||||
Construction in process | 409.6 | 271.7 | |||||
Base gas | 134.0 | 132.1 | |||||
Salt deposits | 41.6 | 41.6 | |||||
Office furniture and equipment | 16.9 | 15.6 | |||||
2,160.7 | 1,857.8 | ||||||
Less: accumulated depreciation | 450.2 | 322.8 | |||||
Total property, plant and equipment, net | $ | 1,710.5 | $ | 1,535.0 | |||
Depreciation expense totaled $147.8 million, $154.6 million and $126.3 million for the years ended September 30, 2012, 2011 and 2010, respectively. Depletion expense totaled $0.2 million for each of the years ended September 30, 2012, 2011 and 2010.
At September 30, 2012 and 2011, the Company capitalized interest of $14.8 million and $16.2 million, respectively, related to certain midstream asset expansion projects.
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Notes to Consolidated Financial Statements (Continued)
Intangible Assets
Intangible assets consisted of the following at September 30, 2012 and 2011, respectively (in millions):
September 30, | |||||||
2012 | 2011 | ||||||
Customer accounts | $ | 41.2 | $ | 39.7 | |||
(accumulated amortization—customer accounts) | (13.7 | ) | (12.8 | ) | |||
Covenants not to compete | 4.2 | 7.4 | |||||
(accumulated amortization—covenants not to compete) | (0.2 | ) | (6.9 | ) | |||
Deferred financing and other costs | 17.1 | 49.5 | |||||
(accumulated amortization—deferred financing costs) | (7.3 | ) | (9.3 | ) | |||
Total intangible assets, net | $ | 41.3 | $ | 67.6 | |||
Amortization and interest expense for the years ended September 30, 2012, 2011 and 2010, amounted to $27.8 million, $43.4 million and $40.3 million, respectively.
Note 5. Assets Held for Sale
As discussed in Note 1, the retail propane operations were contributed to SPH on August 1, 2012. For comparative purposes, the September 30, 2011 balance sheet has classified the disposed retail propane assets and liabilities as held for sale.
The following table details the assets and liabilities held for sale at September 30, 2011 (in millions):
September 30, | |||
2011 | |||
Assets held for sale | |||
Accounts receivable, less allowance for doubtful accounts of $2.4 million | $ | 54.8 | |
Inventories | 57.8 | ||
Prepaid expenses and other current assets | 2.1 | ||
Other assets | 0.5 | ||
Current assets held for sale | 115.2 | ||
Property, plant and equipment, net | 494.4 | ||
Intangible assets, net | 316.2 | ||
Goodwill | 336.1 | ||
Total assets held for sale | $ | 1,261.9 | |
Liabilities held for sale | |||
Accounts payable | $ | 0.6 | |
Accrued expenses | 13.1 | ||
Customer deposits | 52.0 | ||
Obligations under noncompetition agreements and notes to former owners of businesses acquired | 16.4 | ||
Total liabilities held for sale | $ | 82.1 | |
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Notes to Consolidated Financial Statements (Continued)
During the year ended September 30, 2012, the Company recorded a gain on the disposal of its retail propane operations of $589.5 million. The components of the gain are as follows (in millions):
Retail propane assets | $ | (1,209.4 | ) |
Retail propane liabilities | 36.3 | ||
Senior debt | 1,187.0 | ||
SPH common units | 590.2 | ||
Transaction costs | (14.6 | ) | |
Total gain on disposal | $ | 589.5 | |
The Company distributed the SPH common units acquired in the disposition on September 14, 2012. The Company accounted for its investment in SPH during the 45 days it held the units in accordance with the equity method. The drop in the SPH unit price during the holding period required the Company to record an impairment loss prior to distributing the units. The total loss recorded by the Company related to the period in which the units were held amounted to $47.6 million.
Note 6. Risk Management
The Company is exposed to certain market risks related to its ongoing business operations. These risks include exposure to changing commodity prices as well as fluctuations in interest rates. The Company utilizes derivative instruments to manage its exposure to fluctuations in commodity prices, which is discussed more fully below. The Company also periodically utilizes derivative instruments to manage its exposure to fluctuations in interest rates, which is discussed more fully in Note 8. Additional information related to derivatives is provided in Note 2 and Note 7.
Commodity Derivative Instruments and Price Risk Management
Risk Management Activities
Inergy sells NGLs to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of propane. Inergy will enter into offsetting positions to economically hedge against the exposure its customer contracts create, however does not designate these instruments as hedging instruments for accounting purposes. These instruments are marked to market with the changes in the market value reflected in cost of product sold. Inergy attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in cost of product sold related to these instruments.
Cash Flow Hedging Activity
Prior to the disposition of its retail propane operations, the Company entered into derivative instruments to hedge a significant portion of its exposure to fluctuations in commodity prices as a result of entering into fixed price contracts with certain of its retail customers. The Company designated these instruments as cash flow hedges. As a result of the disposition of the retail propane operations, the Company no longer anticipates utilizing cash flow hedges for commodity price risk. However, existing cash flow hedges in place at the time of the disposition will remain in OCI until the forecasted transaction takes place, the bulk of which will be in the first two quarters of fiscal 2013. The forecasted transaction is still expected to take place due to the supply arrangement with SPH.
Fair Value Hedging Activity
Inergy will enter into derivative instruments to hedge its exposure to fluctuating commodity prices that results from maintaining its NGL inventory. These instruments hedging NGL inventory qualify to be treated as fair value hedges. This accounting treatment requires the fair value changes in both the derivative instruments and the hedged inventory to be recorded in cost of product sold.
A significant amount of inventory held in bulk storage facilities is hedged as it is not expected to be sold in the immediate future and is therefore exposed to fluctuations in commodity prices.
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Notes to Consolidated Financial Statements (Continued)
Commodity Price and Credit Risk
Notional Amounts and Terms
The notional amounts and terms of the Company's derivative financial instruments included the following at September 30, 2012, and September 30, 2011 (in millions):
September 30, 2012 | September 30, 2011 | ||||||||||
Fixed Price Payor | Fixed Price Receiver | Fixed Price Payor | Fixed Price Receiver | ||||||||
Propane, crude and heating oil (barrels) | 7.8 | 9.2 | 10.1 | 10.6 | |||||||
Natural gas (MMBTU’s) | 11.8 | 11.6 | 0.1 | — | |||||||
Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not reflect the Company's monetary exposure to market or credit risks.
Fair Value of Derivative Instruments
The following tables detail the amount and location on the Company's consolidated balance sheets and consolidated statements of operations related to all of its derivatives (in millions):
Amount of Gain (Loss) Recognized in Net Income from Derivatives | Amount of Gain (Loss) Recognized in Net Income on Item Being Hedged | ||||||||||||||
Year Ended September 30, | Year Ended September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
Derivatives in fair value hedging relationships: | |||||||||||||||
Commodity(a) | $ | (2.1 | ) | $ | 8.3 | $ | 2.6 | $ | (6.5 | ) | |||||
Debt(b) | — | 0.5 | — | (0.5 | ) | ||||||||||
Total fair value of derivatives | $ | (2.1 | ) | $ | 8.8 | $ | 2.6 | $ | (7.0 | ) | |||||
Amount of Gain (Loss) Recognized in OCI on Effective Portion of Derivatives | Amount of Gain (Loss) Reclassified from OCI to Net Income | Amount of Gain (Loss) Recognized in Net Income on Ineffective Portion of Derivatives & Amount Excluded from Testing | |||||||||||||||||||||
Year Ended September 30, | Year Ended September 30, | Year Ended September 30, | |||||||||||||||||||||
2012 | 2011 | 2012 | 2011 | 2012 | 2011 | ||||||||||||||||||
Derivatives in cash flow hedging relationships: | |||||||||||||||||||||||
Commodity(c) | $ | (6.8 | ) | $ | (6.3 | ) | $ | (1.8 | ) | $ | 4.9 | $ | — | $ | — | ||||||||
Debt(e) | (3.8 | ) | (4.3 | ) | (0.6 | ) | — | — | — | ||||||||||||||
$ | (10.6 | ) | $ | (10.6 | ) | $ | (2.4 | ) | $ | 4.9 | $ | — | $ | — | |||||||||
Amount of Gain (Loss) Recognized in Net Income from Derivatives | |||||||
Year Ended September 30, | |||||||
2012 | 2011 | ||||||
Derivatives not designated as hedging instruments: | |||||||
Commodity(d) | $ | 14.6 | $ | 11.1 | |||
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Notes to Consolidated Financial Statements (Continued)
(a) | The gain (loss) on both the derivative and the item being hedged are located in cost of product sold in the consolidated statements of operations. |
(b) | The gain (loss) on both the derivative and the item being hedged are located in interest expense in the consolidated statements of operations. |
(c) | The gain (loss) on the amount reclassified from OCI into income, the ineffective portion and the amount excluded from effectiveness testing are included in cost of product sold. |
(d) | The gain (loss) is recognized in cost of product sold. |
(e) | The gain (loss) on the amount reclassified from OCI into income, the ineffective portion and the amount excluded from effectiveness testing are included in interest expense. |
All contracts subject to price risk had a maturity of twenty-four months or less; however, 98% of the contracts expire within twelve months.
Credit Risk
Inherent in the Company's contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Inergy takes an active role in managing credit risk and has established control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of September 30, 2012 and 2011, were energy marketers and propane retailers, resellers and dealers.
Certain of the Company's derivative instruments have credit limits that require the Company to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as the Company's established credit limit with the respective counterparty. If the Company's credit rating were to change, the counterparties could require the Company to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in the Company's credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position on September 30, 2012, is $11.3 million for which the Company has posted collateral of $3.3 million and $8.8 million of NYMEX margin deposit in the normal course of business. The Company has received collateral of $12.9 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty.
Note 7. Fair Value Measurements
FASB Accounting Standards Codification Subtopic 820-10 (“820-10”) establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:
• | Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and US government treasury securities. |
• | Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter (“OTC”) forwards, options and physical exchanges. |
• | Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. |
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Notes to Consolidated Financial Statements (Continued)
As of September 30, 2012, the Company held certain assets and liabilities that are required to be measured at fair value on a recurring basis. These included the Company’s derivative instruments related to heating oil, crude oil, NGLs and interest rates as well as the portion of inventory that is hedged in a qualifying fair value hedge. The Company’s derivative instruments consist of forwards, swaps, futures, physical exchanges and options.
Certain of the Company’s derivative instruments are traded on the NYMEX. These instruments have been categorized as level 1.
The Company’s derivative instruments also include OTC contracts, which are not traded on a public exchange. The fair values of these derivative instruments are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. These instruments have been categorized as level 2.
The Company’s inventory that is the hedged item in a qualifying fair value hedge is valued based on prices quoted from observable sources and verified with broker quotes. This inventory has been categorized as level 2.
The Company’s OTC options are valued based on Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The inputs utilized in the model are based on publicly available information as well as broker quotes. These options have been categorized as level 2.
No changes in valuation techniques were made by the Company during the year ended September 30, 2012. However, during the current fiscal year, the Company re-evaluated the inputs used to calculate the fair value of its OTC options noting the inputs qualified as level 2. The fair values of the OTC options presented as level 3 in the prior year have been reclassified to level 2 to conform to current year presentation.
The assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2012 and 2011, (in millions):
September 30, 2012 | |||||||||||||||||||||||||||||||
Fair Value of Derivatives | |||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Designated as Hedges | Not Designated as Hedges | Netting Agreements(a) | Total | ||||||||||||||||||||||||
Assets | |||||||||||||||||||||||||||||||
Assets from price risk management | $ | 2.7 | $ | 51.3 | $ | — | $ | 54.0 | $ | 9.8 | $ | 44.2 | $ | (16.5 | ) | $ | 37.5 | ||||||||||||||
Inventory | — | 73.2 | — | 73.2 | — | — | — | 73.2 | |||||||||||||||||||||||
SPH units | 5.9 | — | — | 5.9 | — | — | — | 5.9 | |||||||||||||||||||||||
Total assets at fair value | $ | 8.6 | $ | 124.5 | $ | — | $ | 133.1 | $ | 9.8 | $ | 44.2 | $ | (16.5 | ) | $ | 116.6 | ||||||||||||||
Liabilities | |||||||||||||||||||||||||||||||
Liabilities from price risk management | $ | 2.0 | $ | 31.1 | $ | — | $ | 33.1 | $ | 11.3 | $ | 21.8 | $ | (12.2 | ) | $ | 20.9 | ||||||||||||||
Interest rate swap | — | 7.5 | — | 7.5 | 7.5 | — | — | 7.5 | |||||||||||||||||||||||
Total liabilities at fair value | $ | 2.0 | $ | 38.6 | $ | — | $ | 40.6 | $ | 18.8 | $ | 21.8 | $ | (12.2 | ) | $ | 28.4 | ||||||||||||||
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Notes to Consolidated Financial Statements (Continued)
September 30, 2011 | |||||||||||||||||||||||||||||||
Fair Value of Derivatives | |||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Designated as Hedges | Not Designated as Hedges | Netting Agreements(a) | Total | ||||||||||||||||||||||||
Assets | |||||||||||||||||||||||||||||||
Assets from price risk management | $ | 1.2 | $ | 27.4 | $ | — | $ | 28.6 | $ | 8.8 | $ | 19.8 | $ | (11.5 | ) | $ | 17.1 | ||||||||||||||
Inventory | — | 147.7 | — | 147.7 | — | — | — | 147.7 | |||||||||||||||||||||||
Interest rate swap | — | 0.5 | — | 0.5 | 0.5 | — | — | 0.5 | |||||||||||||||||||||||
Total assets at fair value | $ | 1.2 | $ | 175.6 | $ | — | $ | 176.8 | $ | 9.3 | $ | 19.8 | $ | (11.5 | ) | $ | 165.3 | ||||||||||||||
Liabilities | |||||||||||||||||||||||||||||||
Liabilities from price risk management | $ | 0.9 | $ | 18.1 | $ | — | $ | 19.0 | $ | 5.4 | $ | 13.6 | $ | — | $ | 19.0 | |||||||||||||||
Interest rate swap | $ | — | $ | 4.3 | $ | — | $ | 4.3 | $ | 4.3 | $ | — | $ | — | $ | 4.3 | |||||||||||||||
Total liabilities at fair value | $ | 0.9 | $ | 22.4 | $ | — | $ | 23.3 | $ | 9.7 | $ | 13.6 | $ | — | $ | 23.3 | |||||||||||||||
(a) | Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions as well as cash collateral held or placed with the same counterparties. |
Note 8. Long-Term Debt
Long-term debt consisted of the following at September 30, 2012 and 2011, respectively (in millions):
September 30, | |||||||
2012 | 2011 | ||||||
Inergy credit agreement: | |||||||
Revolving loan facility | $ | 311.7 | $ | 81.2 | |||
Term loan facility | — | 300.0 | |||||
Inergy senior unsecured notes | 11.5 | 1,445.1 | |||||
Inergy fair value hedge adjustment on senior unsecured notes | — | 0.5 | |||||
Inergy bond/swap premium | — | 13.8 | |||||
Inergy bond discount | — | (5.3 | ) | ||||
Inergy obligations under noncompetition agreements and notes to former owners of businesses acquired | 3.5 | 1.3 | |||||
NRGM credit facility | 416.5 | — | |||||
Total debt | 743.2 | 1,836.6 | |||||
Less: current portion | 3.4 | 3.2 | |||||
Total long-term debt | $ | 739.8 | $ | 1,833.4 | |||
Credit Agreement
On November 24, 2009, Inergy entered into a secured credit facility (“Credit Agreement”) which, at the time, provided borrowing capacity of up to $525 million in the form of a $450 million revolving general partnership credit facility (“General Partnership Facility”) and a $75 million working capital credit facility (“Working Capital Facility”). This facility was to mature on November 22, 2013. Borrowings under these secured facilities are available for working capital needs, future acquisitions, capital expenditures and other general partnership purposes, including the refinancing of existing indebtedness under the former credit facility.
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Notes to Consolidated Financial Statements (Continued)
On February 2, 2011, Inergy amended and restated the Credit Agreement to add a $300 million term loan facility (the “Term Loan Facility”). The term loan was repaid in full in December 2011 as discussed below. The term loan was to mature on February 2, 2015, and bear interest, at Inergy's option, subject to certain limitations, at a rate equal to the following:
• | the Alternate Base Rate, which is defined as the higher of (i) the federal funds rate plus 0.50%; (ii) JP Morgan’s prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 1.00% to 2.25%; or |
• | the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.00% to 3.25%. |
On July 28, 2011, Inergy further amended its Credit Agreement to (i) raise the aggregate revolving commitment from $525 million to $700 million (“Revolving Loan Facility”) with the amount existing as a singular tranche, (ii) reduce the applicable rate on revolving loans and commitment fees, (iii) modify and refresh certain covenants and covenant baskets, and (iv) extend the maturity date from November 22, 2013 to July 28, 2016.
On April 13, 2012, Inergy further amended its Credit Agreement. This amendment, among other things, (i) permitted Inergy to sell up to 5,000,000 of the Inergy Midstream common units that Inergy owns, (ii) permitted Inergy to sell US Salt, (iii) decreased the aggregate revolving commitment and general partnership commitment from $700 million to $550 million, and (iv) adjusted several of the financial covenants.
On July 26, 2012, Inergy further amended its Credit Agreement in order to (i) permit Inergy to enter into a series of transactions as described in the Contribution Agreement dated as of April 25, 2012 among Inergy and SPH, (ii) permit Inergy to repurchase, repay or redeem all or any portion of the senior notes that remain outstanding after the closing of the Contribution Agreement, (iii) modify certain negative and financial covenants under the Credit Agreement, and (iv) allow Inergy to redeem, buy back or otherwise acquire up to $100 million of its common units on or prior to March 31, 2013 subject to meeting certain financial covenant requirements. This amendment did not become effective until the contribution of Inergy's retail propane assets to SPH closed on August 1, 2012. In conjunction with the close of this transaction, $1,187.0 million in Inergy senior notes were exchanged for SPH senior notes and cash paid directly to noteholders, thereby eliminating the senior notes from Inergy's consolidated balance sheet on August 1, 2012.
The Credit Agreement contains various covenants and restrictive provisions that limit its ability to, among other things:
• | incur additional debt; |
• | make distributions on or redeem or repurchase units; |
• | make certain investments and acquisitions; |
• | incur or permit certain liens to exist; |
• | enter into certain types of transactions with affiliates; |
• | merge, consolidate or amalgamate with another company; and |
• | transfer or otherwise dispose of assets. |
The Credit Agreement contains the following financial covenants:
• | the ratio of Inergy's total funded debt (as defined in the Credit Agreement) to consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.0; and |
• | the ratio of Inergy's consolidated EBITDA to consolidated interest expense (as defined in the Credit Agreement), for the four fiscal quarters then most recently ended, must not be less than 2.50 to 1.0. |
If Inergy should fail to perform its obligations under these and other covenants, the Revolving Loan Facility could be terminated and any outstanding borrowings, together with accrued interest, under the Credit Agreement could be declared immediately due and payable. The Credit Agreement also has cross default provisions that apply to any other material indebtedness of Inergy, excluding the debt of Inergy's majority-owned subsidiary, Inergy Midstream.
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Notes to Consolidated Financial Statements (Continued)
All borrowings under the Credit Agreement are generally secured by substantially all of Inergy's assets and the equity interests in all of Inergy's wholly owned subsidiaries, and loans thereunder bear interest, at Inergy's option, subject to certain limitations, at a rate equal to the following:
• | the Alternate Base Rate, which is defined as the higher of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 2.00%; or |
• | the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 3.00%. |
In conjunction with the Inergy Midstream IPO, on December 21, 2011, Inergy entered into the following transactions:
• | Entered into a $255 million unsecured promissory note with JPMorgan Chase Bank (“Promissory Note”). The promissory note was assumed by Inergy Midstream and retired in full by Inergy Midstream utilizing proceeds from the IPO. |
• | Paid in full the $300 million balance outstanding on the Term Loan Facility. |
• | Tendered for substantially all the $95 million outstanding on the 2015 Senior Notes. |
• | Tendered for $150 million of the $750 million outstanding on the 2021 Senior Notes. |
• | The last three debt payments described above were funded by Inergy from the $255 million proceeds from the Promissory Note, proceeds received from Inergy Midstream as part of the IPO and borrowings on the Revolving Loan Facility. |
At September 30, 2012, the balance outstanding under the Credit Agreement was $311.7 million. At September 30, 2011, the balance outstanding under the Credit Agreement was $381.2 million, of which $300.0 million was borrowed under the Term Loan Facility and $81.2 million under the Revolving Loan Facility. The interest rates of the Revolving Loan Facility are based on prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.99% and 5.00% at September 30, 2012, and 2.73% and 4.75% at September 30, 2011. The interest rate on the Term Loan Facility was based on LIBOR plus the applicable spread, resulting in an interest rate of 3.23% at September 30, 2011. Availability under the Credit Agreement amounted to $184.0 million and $575.3 million at September 30, 2012 and 2011, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $54.3 million and $43.5 million at September 30, 2012 and 2011, respectively.
At September 30, 2012, the Company was in compliance with the debt covenants in the Credit Agreement and senior unsecured notes.
Inergy Midstream's Credit Facility
On December 21, 2011, Inergy Midstream entered into a new $500 million revolving credit facility (“NRGM Credit Facility”) with a December 2016 maturity date. The NRGM Credit Facility is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The NRGM Credit Facility has an accordion feature that allows Inergy Midstream to increase loan commitments by up to $250 million, subject to the lenders' agreement and the satisfaction of certain conditions. In addition, its credit facility includes a sub-limit up to $10 million for same-day swing line advances and a sub-limit up to $100 million for letters of credit.
On April 16, 2012, Inergy Midstream exercised a portion of its accordion feature under the NRGM Credit Facility and increased the loan commitments thereunder by $100 million. The aggregate amount of revolving loan commitments under the NRGM Credit Facility now equals $600 million. Inergy Midstream may continue to increase the loan commitments by up to $150 million, subject to the lenders' agreement and the satisfaction of certain conditions.
At September 30, 2012, the balance outstanding under the NRGM Credit Facility was $416.5 million. Outstanding standby letters of credit under the NRGM Credit Facility amounted to $2.0 million at September 30, 2012. As a result, Inergy Midstream has approximately $181.5 million of remaining capacity at September 30, 2012, subject to compliance with any applicable covenants under such facility.
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Notes to Consolidated Financial Statements (Continued)
Inergy and its wholly owned subsidiaries do not provide credit support or guarantee any amounts outstanding under the NRGM Credit Facility.
The NRGM Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things:
• | incur additional debt; |
• | make distributions on or redeem or repurchase units; |
• | make certain investments and acquisitions; |
• | incur or permit certain liens to exist; |
• | enter into certain types of transactions with affiliates; |
• | merge, consolidate or amalgamate with another company; and |
• | transfer or otherwise dispose of assets. |
If Inergy Midstream fails to perform its obligations under these and other covenants, the lenders' credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under its credit facility could be declared immediately due and payable. The NRGM Credit Facility also has cross default provisions that apply to any other material indebtedness of Inergy Midstream.
Borrowings under the NRGM Credit Facility are generally secured by pledges of the equity interests in Inergy Midstream's wholly owned subsidiaries, liens on substantially all of its assets and guarantees issued by all of Inergy Midstream's subsidiaries. Borrowings under the NRGM Credit Facility (other than swing line loans) will bear interest at its option at either:
• | the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 1.75% depending on our most recent total leverage ratio; or |
• | the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 2.75% depending on Inergy Midstream's most recent total leverage ratio. |
Swing line loans bear interest at the Alternate Base Rate plus a margin varying from 0.75% to 1.75%. The unused portion of the NRGM Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to its most recent total leverage ratio. Interest on Alternative Base Rate loans is payable quarterly or, if the Adjusted LIBO Rate applies, it may be paid at more frequent intervals.
The NRGM Credit Facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.00 and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.00.
Senior Unsecured Notes
2015 Senior Notes
In conjunction with the Inergy Midstream IPO on December 21, 2011, Inergy tendered for substantially all the $95 million outstanding on these notes, leaving a balance of $0.8 million at September 30, 2012.
2018 Senior Notes
On September 27, 2010, Inergy and its wholly-owned subsidiary, Inergy Finance Corp, issued $600 million aggregate principal amount of 7% senior unsecured notes due 2018 (the “2018 Senior Notes”) under Rule 144A to eligible purchasers. The 7% notes mature on October 1, 2018.
The majority of these notes were exchanged during the year ended September 30, 2012 in conjunction with the contribution of Inergy's retail propane operations to SPH, leaving a balance of $10.1 million at September 30, 2012.
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Notes to Consolidated Financial Statements (Continued)
2021 Senior Notes
As discussed above, in conjunction with the Inergy Midstream IPO on December 21, 2011, Inergy tendered for $150 million of the $750 million outstanding on these notes. The majority of the remaining notes were exchanged during the year ended September 30, 2012, in conjunction with the sale of retail to SPH, leaving a balance of $0.6 million at September 30, 2012.
Interest Rate Swaps
During fiscal year 2011, Inergy entered into eleven interest rate swaps, one of which was scheduled to mature in 2015 (notional amount of $25 million) and the remaining ten were scheduled to mature in 2018 (aggregate notional amount of $250 million). In August 2011, Inergy's ten interest rate swaps maturing in 2018 were terminated. In December 2011, the remaining interest rate swap maturing in 2015 was terminated and the Company entered into a new interest rate swap scheduled to mature in 2018 (notional amount of $50 million). This swap agreement, which was to expire on the same date as the maturity date of the related senior unsecured notes and contained call provisions consistent with the underlying senior unsecured notes, required the counterparty to pay Inergy an amount based on the stated fixed interest rate due every nine months. In exchange, Inergy was required to make semi-annual floating interest rate payments on the same dates to the counterparty based on an annual interest rate equal to the one-month LIBOR interest rate plus a spread of 5.218% applied to the same aggregate notional amount of $50 million. This swap agreement had been accounted for as a fair value hedge. Amounts received or paid under the agreement were accrued and recognized over the life of the agreement as an adjustment to interest expense. In May 2012, this interest rate swap was terminated.
Inergy is party to six interest rate swap agreements scheduled to mature in 2015 to hedge its exposure to variable interest payments due under the Credit Agreement. Certain of these swap agreements with a notional amount of $100.0 million do not commence quarterly settlements until October 1, 2012. These swap agreements require Inergy to pay the counterparty an amount based on fixed rates from 0.84% to 2.52% due quarterly. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to Inergy based on the three-month LIBOR applied to the same aggregate notional amount of $225.0 million. These swap agreements have been accounted for as cash flow hedges.
Notes Payable and Other Obligations
Non-interest bearing obligations due under noncompetition agreements and other note payable agreements consisted of agreements between Inergy and the sellers of NGL logistics companies acquired from fiscal years 2003 through 2012 with payments due through 2022 and imputed interest ranging from 6.75% to 8.00%. Non-interest bearing obligations consisted of $4.7 million and $1.4 million in total payments due under agreements, less unamortized discount based on imputed interest of $1.2 million and $0.2 million at September 30, 2012 and 2011, respectively.
The aggregate amounts of principal to be paid on the outstanding long-term debt and notes payable during the next five years ending September 30 and thereafter are as follows (in millions):
Long-Term Debt and Notes Payable | |||
2013 | $ | 3.4 | |
2014 | 0.2 | ||
2015 | 1.0 | ||
2016 | 310.2 | ||
2017 | 415.2 | ||
Thereafter | 13.2 | ||
Total debt | $ | 743.2 | |
Accrued interest, classified in accrued expense on the consolidated balance sheets, at September 30, 2012 and 2011, was $2.6 million and $31.5 million, respectively.
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Notes to Consolidated Financial Statements (Continued)
Note 9. Leases
Tres Palacios leases the surface and subsurface rights necessary to operate the storage facility under an operating lease that expires on December 31, 2037, which is subject to automatic renewal for two 20-year extension periods unless Tres Palacios elects not to extend the term of the lease. The lease payments vary based on the FERC-certificated working gas capacity of the caverns which are in service as well as an incremental payment for physical volumes of gas injected and / or withdrawn from the caverns in service.
Inergy also has certain other noncancelable operating leases, mainly for office space and vehicles, the majority of which expire at various times over the next ten years. Certain of these leases contain terms that provide that the rental payment be indexed to published information.
Future minimum lease payments under noncancelable operating leases for the next five years ending September 30 and thereafter consist of the following (in millions):
Year Ending September 30, | |||
2013 | $ | 15.5 | |
2014 | 15.3 | ||
2015 | 15.4 | ||
2016 | 18.2 | ||
2017 | 17.5 | ||
Thereafter | 323.7 | ||
Total minimum lease payments | $ | 405.6 | |
Rent expense for operating leases for the years ended September 30, 2012, 2011 and 2010, totaled $28.1 million, $25.4 million and $15.0 million, respectively.
Note 10. Income Taxes
The provision for income taxes for the years ended September 30, 2012, 2011, and 2010 consisted of the following (in millions):
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Current: | |||||||||||
Federal | $ | 1.0 | $ | 0.5 | $ | 0.3 | |||||
State | 0.4 | 0.7 | 0.2 | ||||||||
Total current | 1.4 | 1.2 | 0.5 | ||||||||
Deferred: | |||||||||||
Federal | 0.4 | (0.5 | ) | (0.3 | ) | ||||||
State | — | — | — | ||||||||
Total deferred | 0.4 | (0.5 | ) | (0.3 | ) | ||||||
Provision for income taxes | $ | 1.8 | $ | 0.7 | $ | 0.2 | |||||
The effective rate differs from the statutory rate because the income tax provision for the years ended September 30, 2012, 2011 and 2010, relates to taxable income of the corporations as discussed in Note 2.
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Notes to Consolidated Financial Statements (Continued)
Deferred income taxes related to IPCHA reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Components of the deferred income taxes at September 30, 2012 and 2011, are as follows (in millions):
September 30, | |||||||
2012 | 2011 | ||||||
Deferred tax liabilities: | |||||||
Basis difference in stock of acquired company | $ | (20.6 | ) | $ | (20.2 | ) | |
Total deferred tax liability | $ | (20.6 | ) | $ | (20.2 | ) | |
Note 11. Partners’ Capital
Common Unit Offerings
On March 16, 2011, Inergy's new shelf registration statement (File No. 333-172312) was declared effective by the Securities and Exchange Commission for the periodic sale of up to $1.5 billion of common units, partnership securities and debt securities, or any combination thereof.
On June 6, 2011, Inergy issued 9,000,000 common units in a public offering. Inergy used the net proceeds from this offering to repay borrowings under its Revolving Loan Facility, to fund ongoing expansion projects in its midstream business and for general partnership purposes. Net proceeds from this issuance amounted to $311.2 million.
Inergy Midstream
On December 21, 2011, Inergy Midstream completed its IPO. Inergy Midstream sold 16,000,000 common units to public investors and the underwriters exercised their option to purchase an additional 2,400,000 common units.
On May 14, 2012, Inergy Midstream issued 473,707 units directly to Inergy in conjunction with the contribution of US Salt.
Class B Units
The Class B units have similar rights and obligations of Inergy common units except that the units will pay distributions in kind rather than in cash for a certain period of time. During the three-month period ended December 31, 2011, Inergy distributed 205,748 Class B units. Immediately following this distribution, 50% of the Class B units outstanding that were held by each holder of a Class B unit, and all of the additional Class B units issued in kind as a distribution, converted into Inergy common units at a conversion ratio of one Class B unit for one Inergy common unit. This resulted in the conversion of 6,586,968 Class B units into Inergy common units. The remaining Class B units converted into Inergy common units in the first quarter of fiscal 2013. For a complete description of the Class B units, please see the Third Amended and Restated Agreement of Limited Partnership of Inergy, filed on Form 8-K on November 5, 2010.
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Notes to Consolidated Financial Statements (Continued)
Quarterly Distributions of Available Cash
A summary of the Company's limited partner quarterly distribution for the year ended September 30, 2012, is presented below:
Year Ended | ||||||||
September 30, 2012 | ||||||||
Record Date | Payment Date | Per Unit Rate | Distribution Amount (in millions) | |||||
November 7, 2011 | November 14, 2011 | $0.705 | $ | 83.9 | ||||
February 7, 2012 | February 14, 2012 | $0.705 | $ | 88.7 | ||||
May 8, 2012 | May 15, 2012 | $0.375 | $ | 47.1 | ||||
August 7, 2012 | August 14, 2012 | $0.375 | $ | 47.1 | ||||
$ | 266.8 | |||||||
Certain distributions to restricted unit holders were classified as stock based compensation expense as the distribution was associated with a restricted unit that is not currently expected to vest due to certain performance criteria.
A summary of Holdings and Inergy's limited partner quarterly distributions for the three months ended December 31, 2010, (prior to the merger) is presented below:
Three Months Ended | |||||||
December 31, 2010 | |||||||
Holdings | Inergy | ||||||
Record date | October 22, 2010 | October 22, 2010 | |||||
Payment date | October 29, 2010 | October 29, 2010 | |||||
Per unit rate | $ | 0.442 | $ | 0.705 | |||
Distribution amount (in millions) | $ | 21.1 | $ | 76.1 | |||
A summary of the Company's limited partner quarterly distribution for the nine months ended September 30, 2011, (after the merger) is presented below:
Nine Months Ended | ||||||||||
September 30, 2011 | ||||||||||
Record Date | Payment Date | Per Unit Rate | Distribution Amount (in millions) | |||||||
February 7, 2011 | February 14, 2011 | $ | 0.705 | $ | 77.4 | |||||
May 6, 2011 | May 13, 2011 | $ | 0.705 | 77.6 | ||||||
August 5, 2011 | August 12, 2011 | $ | 0.705 | 84.0 | ||||||
$ | 239.0 | |||||||||
On November 14, 2012, Inergy paid a quarterly distribution of $0.290 per limited partner unit to unitholders of record on November 7, 2012.
Suburban Propane Partners, L.P. Common Unit Distribution
On August 1, 2012, Inergy received, as partial consideration for the contribution of its retail propane operations to SPH, approximately 14.2 million SPH common units. Under terms of the contribution agreement, Inergy agreed to distribute on a pro rata basis approximately 14.1 million of the SPH common units to the Inergy unitholders. This distribution of SPH common units took place after the market closed on September 14, 2012, and approximated 0.108 SPH common units for each Inergy limited partner unit outstanding on August 29, 2012. The value of the SPH common units distributed was approximately $536.5 million. In lieu of SPH common units, all Inergy restricted unitholders received a cash distribution in an aggregate amount of $6.1 million.
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Notes to Consolidated Financial Statements (Continued)
Inergy, L.P. Unit Purchase Plan
Inergy's general partner sponsors a unit purchase plan for its employees and the employees of its affiliates. The unit purchase plan permits participants to purchase common units in market transactions from Inergy, the general partners or any other person. All purchases made have been in market transactions, although the plan allows Inergy to issue additional units. Inergy has reserved 100,000 units for purchase under the unit purchase plan. As determined by the compensation committee, the general partner may match each participant's cash base pay or salary deferrals by an amount up to 10% of such deferrals and have such amount applied toward the purchase of additional units. The general partner has also agreed to pay the brokerage commissions, transfer taxes and other transaction fees associated with a participant's purchase of common units. The maximum amount that a participant may elect to have withheld from his or her salary or cash base pay with respect to unit purchases in any calendar year may not exceed 10% of his or her base salary or wages for the year. Units purchased on behalf of a participant under the unit purchase plan generally are to be held by the participant for at least one year. To the extent a participant desires to sell or dispose of such units prior to the end of this one year holding period, the participant will be ineligible to participate in the unit purchase plan again until the one year anniversary of the date of such sale. The unit purchase plan is intended to serve as a means for encouraging participants to invest in common units. Units purchased through the unit purchase plan by Inergy and its employees for the fiscal years ended September 30, 2012, 2011 and 2010, were 21,153 units, 13,821 units and 6,877 units, respectively.
Inergy, L.P. Long-Term Incentive Plan
Inergy's general partner sponsors the long-term incentive plan for its employees, consultants and directors and the employees of its affiliates that perform services for Inergy. The long-term incentive plan currently permits the grant of awards covering an aggregate of 11,914,786 common units, which can be granted in the form of unit options, phantom units and/or restricted units. With the exception of 56,000 unit options (exercise prices from $1.92 to $5.34) granted to non-executive employees in exchange for option grants made by the predecessor in fiscal 1999, all of which have been grandfathered into the long-term incentive plan and are presented as grants in the table below, all units granted under the plan will vest in accordance with the Unit Agreements, which typically provide that unit options begin vesting three to five years from the anniversary date of the applicable grant date. Shares issued as a result of unit option exercises are newly issued shares. Inergy has not issued new unit options since fiscal 2008.
Restricted Units
A restricted unit is a common unit that vests over a period of time yet during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control as defined in the long-term incentive plan. If a grantee's employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.
The Company intends the restricted units to serve as a means of incentive compensation for performance and as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy will receive no cash remuneration for the units.
Inergy granted 91,216; 474,468 and 299,983 restricted units during the years ended September 30, 2012, 2011 and 2010, respectively. Some of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of the restricted units vest 25% after the third year, 25% after the fourth year and 50% after the fifth year. Some of these units are subject to the achievement of certain specified performance objectives and failure to meet the performance objectives will result in forfeiture and cancellation of the restricted units. The Company recognizes expense on these units each quarter by multiplying the closing price of the Company's common units on the date of grant by the number of units granted, and expensing that amount over the vesting period utilizing the straight-line method, except for awards with performance conditions which utilize the accelerated method.
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Notes to Consolidated Financial Statements (Continued)
A summary of Inergy's weighted-average grant date fair value for restricted units for the year ended September 30, 2012, is as follows:
Weighted-Average Grant Date Fair Value | Number of Units | |||||
Non-vested at October 1, 2011 | $ | 33.94 | 1,782,395 | |||
Granted during the period ended September 30, 2012 | $ | 17.47 | 91,216 | |||
Vested during the period ended September 30, 2012 | $ | 24.51 | 335,719 | |||
Forfeited during the period ended September 30, 2012 | $ | 33.11 | 29,699 | |||
Non-vested at September 30, 2012 | $ | 27.21 | 1,508,193 | |||
The weighted-average grant date fair value of restricted units granted and vested during the year ended September 30, 2011, amounted to $39.02 and $26.63, respectively. The weighted-average grant date fair value of restricted units granted and vested during the year ended September 30, 2010, amounted to $36.08 and $27.50, respectively. The fair value of restricted units vested during the years ended September 30, 2012, 2011 and 2010, was $8.2 million, $1.5 million and $0.4 million, respectively.
During the quarter ended September 30, 2012, the Company recorded additional amortization on certain awards and made a change in estimate in which it was determined that certain restricted units with performance conditions were no longer going to be met. This change in estimate resulted in the previously recognized unit-based compensation being reversed and also required the distributions previously paid on these awards to be reclassified from distributions to unit-based compensation expense. The aforementioned factors resulted in a net additional amount of unit-based compensation expense of $5.7 million in the quarter ended September 30, 2012 and $11.7 million in the year ended September 30, 2012.
The compensation expense recorded by the Company related to these restricted unit awards was $17.2 million, $5.7 million and $2.3 million for the years ended September 30, 2012, 2011 and 2010, respectively.
As of September 30, 2012, there was $9.6 million of total unrecognized compensation cost related to unvested share-based compensation awards granted to employees under the restricted unit and unit option plans. That cost is expected to be recognized over a five-year period.
Inergy Midstream, L.P. Long-Term Incentive Plan
Inergy Midstream's general partner sponsors the long-term incentive plan for its employees, consultants and directors and the employees of its affiliates that perform services for Inergy Midstream. The long-term incentive plan currently permits the grant of awards covering an aggregate of 7,432,500 common units, which can be granted in the form of unit options, phantom units and/or restricted units. As of September 30, 2012 all long-term incentive plan activity has been issued in the form of restricted units.
Restricted Units
A restricted unit is a common unit that participates in distributions and vests over a period of time yet during such time is subject to forfeiture. The compensation committee may make grants of restricted units to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control as defined in the long-term incentive plan. If a grantee's employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.
Inergy Midstream intends the restricted units to serve as a means of incentive compensation for performance and as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and Inergy Midstream will receive no cash remuneration for the units.
Inergy Midstream granted 383,223 restricted units during the year ended September 30, 2012. Some of the restricted units are 100% vested on the fifth anniversary of the grant date, subject to the provisions as outlined in the restricted unit award agreement. Some of the restricted units vest 25% after the third year, 25% after the fourth year and 50% after the fifth year.
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Notes to Consolidated Financial Statements (Continued)
Inergy Midstream recognizes expense on these units each quarter by multiplying the closing price of its common units on the date of grant by the number of units granted, and expensing that amount over the vesting period on a straight-line basis.
A summary of Inergy Midstream's weighted-average grant date fair value for restricted units for the year ended September 30, 2012, is as follows:
Weighted-Average Grant Date Fair Value | Number of Units | |||||
Non-vested at October 1, 2011 | $ | — | — | |||
Granted during the period ended September 30, 2012 | $ | 21.62 | 383,223 | |||
Vested during the period ended September 30, 2012 | $ | — | — | |||
Forfeited during the period ended September 30, 2012 | $ | — | — | |||
Non-vested at September 30, 2012 | $ | 21.62 | 383,223 | |||
The compensation expense recorded by Inergy Midstream related to these restricted unit awards was $0.7 million for the year ended September 30, 2012.
As of September 30, 2012, there was $7.6 million of total unrecognized compensation cost related to unvested share-based compensation awards granted to employees under the Inergy Midstream restricted unit plan. That cost is expected to be recognized over a five-year period.
Note 12. Employee Benefit Plans
A 401(k) plan is available to all of Inergy's employees after meeting certain requirements. The plan permits employees to make contributions up to 75% of their salary, up to statutory limits, which was $17,000 in 2012. The plan provides for matching contributions by Inergy for employees completing one year of service of at least 1000 hours. Aggregate matching contributions made by Inergy were $1.9 million, $2.2 million and $2.4 million in fiscal 2012, 2011 and 2010, respectively.
Of Inergy's 793 employees, 13% are subject to collective bargaining agreements. For the years ended September 30, 2012, 2011 and 2010, Inergy made contributions on behalf of its union employees to union sponsored defined benefit plans of $2.7 million, $3.3 million and $2.9 million, respectively.
Note 13. Commitments and Contingencies
Inergy periodically enters into agreements with suppliers to purchase fixed quantities of NGLs, distillates and natural gas at fixed prices. At September 30, 2012, the total of these firm purchase commitments was $351.2 million, approximately 99% of which will occur over the course of the next twelve months. The Company also enters into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.
Inergy and Inergy Midstream have entered into certain purchase commitments in connection with the identified growth projects primarily related to the Watkins Glen NGL development project and the MARC I Pipeline. The Watkins Glen NGL development project entails the conversion of certain caverns created by US Salt into 2.1 million barrels of NGL storage. The MARC I Pipeline project is a 39 mile, 30" bi-directional pipeline that will extend between the Stagecoach south lateral interconnect with Tennessee Gas Pipeline Company's 300 Line near its compressor station 319 and Transco's Leidy Line near its compressor station 517, and will provide 550 MMcf/d of firm transportation capacity. At September 30, 2012, the total of Inergy's and Inergy Midstream's storage and transportation operations' firm purchase commitments was approximately $22.6 million, and the majority of the purchases associated with these commitments are expected to occur over the course of the next twelve months.
Inergy is periodically involved in litigation proceedings. The results of litigation proceedings cannot be predicted with certainty; however, management believes that Inergy does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows.
127
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
In June 2010, Inergy Midstream and CNYOG entered into a letter of intent with Anadarko Petroleum Corporation (“Anadarko”) which contemplated that, subject to certain conditions, Anadarko may exercise an option to acquire up to a 25% ownership interest in the MARC I pipeline. On September 23, 2011, Anadarko filed a complaint against the Company and CNYOG in the Court of Common Pleas in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I pipeline, (ii) the Company refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, the Company breached the letter of intent, and (iii) by refusing to enter into definitive agreements, the Company breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific performance of the letter of intent and monetary damages.
The Company filed its answer to Anadarko's complaint on January 17, 2012 and discovery is ongoing. The Company believes that Anadarko's claims are without merit and intends to vigorously defend themselves in the lawsuit.
Following the announcement of the Inergy and Holdings merger, two class action lawsuits were filed by unitholders of Inergy (the “Inergy Unitholder Lawsuits”) as described in Item 3 of form 10-K as filed with the Securities and Exchange Commission for the fiscal year ended September 30, 2010. The parties to the Inergy Unitholder Lawsuits have entered into a Memorandum of Understanding whereby in consideration for the settlement and dismissal of the claims, the individual Class B unitholders will forego and relinquish a total of 135,539 Class B units to be received as distributions following the date on which the settlement and dismissal become final and no longer appealable. On March 29, 2012, the court approved the terms of the settlement, which included the certification of a settlement class and the dismissal with prejudice of all claims. Also as part of the settlement, the defendants in the Inergy Unitholder Lawsuits other than Inergy must pay fees and expenses to counsel for the plaintiffs in the amount of $1.8 million, which amount is covered by insurance.
Inergy utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers' compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management's estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Inergy's self insurance reserves could be affected if future claims development differs from the historical trends. Inergy believes changes in health care costs, trends in health care claims of its employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. Inergy continually monitors changes in employee demographics, incident and claim type and evaluates its insurance accruals and adjusts its accruals based on its evaluation of these qualitative data points. Inergy is liable for the development of claims for its disposed retail propane operations, provided they were reported prior to August 1, 2012. At September 30, 2012 and 2011, Inergy's self-insurance reserves were $23.8 million and $20.6 million, respectively. The Company estimates that $15.0 million of this balance will be paid subsequent to September 30, 2013. As such, $15.0 million has been classified in other long-term liabilities on the consolidated balance sheets.
Note 14. Segments
Inergy's financial statements reflect two operating and reportable segments: NGL marketing, supply and logistics operations and storage and transportation operations. Inergy's NGL marketing, supply and logistics operations include NGL sales to retailers and resellers of NGL, NGL fractionation and distribution, processing of natural gas and distribution of propane, marketing and price risk management services to other users, retailers and resellers of propane and the results of retail propane operations disposed on August 1, 2012. Inergy's storage and transportation operations include storage and transportation of natural gas and NGLs for third parties and the production and sale of salt products.
The identifiable assets associated with each reportable segment include accounts receivable and inventories. Goodwill, property, plant and equipment and expenditures for property, plant and equipment are also presented for each segment. The net asset/liability from price risk management, as reported in the accompanying consolidated balance sheets, is primarily related to the NGL marketing, supply and logistics segment. Assets and liabilities held for sale for the years ended September 30, 2011 and 2010 relate entirely to the NGL marketing, supply and logistics segment.
128
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Revenues, gross profit, identifiable assets, goodwill, property, plant and equipment and expenditures for property, plant and equipment for each of Inergy's reportable segments are presented below (in millions):
Year Ended September 30, 2012 | |||||||||||||||||||
NGL Marketing, Supply and Logistics Operations | Storage and Transportation Operations | Intersegment Operations | Corporate Assets | Total | |||||||||||||||
Retail revenues | $ | 777.3 | $ | — | $ | — | $ | — | $ | 777.3 | |||||||||
Marketing revenues | 618.9 | — | — | — | 618.9 | ||||||||||||||
Facility revenues | 299.0 | — | (2.3 | ) | — | 296.7 | |||||||||||||
Storage revenues | 12.4 | 209.4 | (11.8 | ) | — | 210.0 | |||||||||||||
Transportation revenues | 75.5 | 28.4 | — | — | 103.9 | ||||||||||||||
Gross profit | 426.8 | 183.8 | — | — | 610.6 | ||||||||||||||
Identifiable assets | 192.4 | 28.3 | — | — | 220.7 | ||||||||||||||
Goodwill | 3.8 | 141.8 | — | 20.2 | 165.8 | ||||||||||||||
Property, plant and equipment | 352.0 | 1,802.2 | — | 6.5 | 2,160.7 | ||||||||||||||
Expenditures for property, plant and equipment | 29.4 | 262.5 | — | 0.6 | 292.5 | ||||||||||||||
Year Ended September 30, 2011 | |||||||||||||||||||
NGL Marketing, Supply and Logistics Operations | Storage and Transportation Operations | Intersegment Operations | Corporate Assets | Total | |||||||||||||||
Retail revenues | $ | 1,050.9 | $ | — | $ | — | $ | — | $ | 1,050.9 | |||||||||
Marketing revenues | 563.1 | — | (0.2 | ) | — | 562.9 | |||||||||||||
Facility revenues | 294.0 | — | (1.5 | ) | — | 292.5 | |||||||||||||
Storage revenues | 5.3 | 195.2 | (4.1 | ) | — | 196.4 | |||||||||||||
Transportation revenues | 37.1 | 14.0 | — | — | 51.1 | ||||||||||||||
Gross profit | 525.0 | 152.8 | — | — | 677.8 | ||||||||||||||
Identifiable assets | 241.7 | 26.3 | — | — | 268.0 | ||||||||||||||
Goodwill | — | 141.8 | — | 20.2 | 162.0 | ||||||||||||||
Property, plant and equipment | 311.8 | 1,533.7 | — | 12.3 | 1,857.8 | ||||||||||||||
Expenditures for property, plant and equipment | 27.2 | 172.1 | — | 0.9 | 200.2 | ||||||||||||||
Year Ended September 30, 2010 | ||||||||||||||
NGL Marketing, Supply and Logistics Operations | Storage and Transportation Operations | Intersegment Operations | Corporate Assets | Total | ||||||||||
Retail revenues | 973.1 | — | — | — | 973.1 | |||||||||
Marketing revenues | 449.8 | — | (0.2 | ) | — | 449.6 | ||||||||
Facility revenues | 183.0 | — | (0.7 | ) | — | 182.3 | ||||||||
Storage revenues | 0.2 | 134.8 | (0.5 | ) | — | 134.5 | ||||||||
Transportation revenues | 34.4 | 12.1 | — | — | 46.5 | |||||||||
Gross profit | 515.1 | 105.0 | — | — | 620.1 | |||||||||
Identifiable assets | 130.2 | 18.0 | — | — | 148.2 | |||||||||
Goodwill | — | 96.4 | — | 20.2 | 116.6 | |||||||||
Property, plant and equipment | 299.6 | 630.2 | — | 12.0 | 941.8 | |||||||||
Expenditures for property, plant and equipment | 26.7 | 57.1 | — | 1.6 | 85.4 | |||||||||
129
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Note 15 - Condensed Consolidating Financial Information
Inergy is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under its outstanding senior notes and credit agreement listed in Note 8 are jointly and severally guaranteed by Inergy's wholly owned domestic subsidiaries. Subsequent to Inergy Midstream's IPO on December 21, 2011, Inergy Midstream and its wholly owned subsidiaries no longer guarantee Inergy's senior notes or credit agreement.
The tables below present condensed consolidated financial statements for Inergy (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2012, and for the year ended September 30, 2012. Comparative financial statements have not been provided as Inergy Midstream was a guarantor of the senior notes in the prior period. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.
Condensed Consolidating Balance Sheet | |||||||||||||||||||
September 30, 2012 | |||||||||||||||||||
(in millions) | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Assets | |||||||||||||||||||
Current assets: | |||||||||||||||||||
Cash and cash equivalents | $ | 2.9 | $ | (2.9 | ) | $ | — | $ | — | $ | — | ||||||||
Accounts receivable | — | 114.3 | 19.3 | — | 133.6 | ||||||||||||||
Inventories | — | 81.5 | 5.6 | — | 87.1 | ||||||||||||||
Other | — | 52.7 | 5.4 | (0.3 | ) | 57.8 | |||||||||||||
Total current assets | 2.9 | 245.6 | 30.3 | (0.3 | ) | 278.5 | |||||||||||||
Property, plant and equipment, net | — | 842.6 | 867.9 | — | 1,710.5 | ||||||||||||||
Goodwill and intangible assets, net | 20.2 | 61.1 | 125.8 | — | 207.1 | ||||||||||||||
Investment in subsidiary | 1,380.6 | — | — | (1,380.6 | ) | — | |||||||||||||
Other assets | — | 7.6 | 3.9 | — | 11.5 | ||||||||||||||
Total assets | $ | 1,403.7 | $ | 1,156.9 | $ | 1,027.9 | $ | (1,380.9 | ) | $ | 2,207.6 | ||||||||
Liabilities and partners' capital | |||||||||||||||||||
Current liabilities: | |||||||||||||||||||
Accounts payable | $ | — | $ | 116.9 | $ | 3.9 | $ | — | $ | 120.8 | |||||||||
Other | 4.6 | 61.0 | 52.9 | (0.3 | ) | 118.2 | |||||||||||||
Total current liabilities | 4.6 | 177.9 | 56.8 | (0.3 | ) | 239.0 | |||||||||||||
Long-term liabilities: | |||||||||||||||||||
Long-term debt, less current portion | 324.8 | — | 415.0 | — | 739.8 | ||||||||||||||
Other long-term liabilities | 28.1 | 15.1 | 0.8 | — | 44.0 | ||||||||||||||
Total long-term liabilities | 352.9 | 15.1 | 415.8 | — | 783.8 | ||||||||||||||
Partners' capital | 1,046.2 | 963.9 | 416.7 | (1,380.6 | ) | 1,046.2 | |||||||||||||
Interest of non-controlling partners in subsidiary | — | — | 138.6 | — | 138.6 | ||||||||||||||
Total partners' capital | 1,046.2 | 963.9 | 555.3 | (1,380.6 | ) | 1,184.8 | |||||||||||||
Total liabilities and partners' capital | $ | 1,403.7 | $ | 1,156.9 | $ | 1,027.9 | $ | (1,380.9 | ) | $ | 2,207.6 | ||||||||
130
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Condensed Consolidating Statements of Operations | |||||||||||||||||||
Year Ended September 30, 2012 | |||||||||||||||||||
(in millions) | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenue: | |||||||||||||||||||
Propane | $ | — | $ | 1,289.0 | $ | — | $ | — | $ | 1,289.0 | |||||||||
Other | — | 539.8 | 189.8 | (11.8 | ) | 717.8 | |||||||||||||
— | 1,828.8 | 189.8 | (11.8 | ) | 2,006.8 | ||||||||||||||
Cost of product sold (excluding depreciation and amortization as shown below): | |||||||||||||||||||
Propane | — | 974.5 | — | — | 974.5 | ||||||||||||||
Other | — | 392.1 | 41.4 | (11.8 | ) | 421.7 | |||||||||||||
— | 1,366.6 | 41.4 | (11.8 | ) | 1,396.2 | ||||||||||||||
Expenses: | |||||||||||||||||||
Operating and administrative | — | 270.4 | 30.4 | — | 300.8 | ||||||||||||||
Depreciation and amortization | — | 119.1 | 50.5 | — | 169.6 | ||||||||||||||
Loss on disposal of assets | — | 5.7 | — | — | 5.7 | ||||||||||||||
Operating income | — | 67.0 | 67.5 | — | 134.5 | ||||||||||||||
Other income (expense): | |||||||||||||||||||
Interest expense, net | (81.8 | ) | — | (1.8 | ) | — | (83.6 | ) | |||||||||||
Early extinguishment of debt | (26.6 | ) | — | — | — | (26.6 | ) | ||||||||||||
Gain on disposal of retail propane operations | 589.5 | — | — | — | 589.5 | ||||||||||||||
Loss on Suburban Propane Partners, L.P. units | (47.6 | ) | — | — | — | (47.6 | ) | ||||||||||||
Other income | — | 1.5 | — | — | 1.5 | ||||||||||||||
Equity in net income of subsidiary | 132.4 | — | — | (132.4 | ) | — | |||||||||||||
Income (loss) before income taxes | 565.9 | 68.5 | 65.7 | (132.4 | ) | 567.7 | |||||||||||||
Provision for income taxes | — | 1.8 | — | — | 1.8 | ||||||||||||||
Net income (loss) | 565.9 | 66.7 | 65.7 | (132.4 | ) | 565.9 | |||||||||||||
Net income attributable to non-controlling partners in subsidiary | — | — | (11.0 | ) | — | (11.0 | ) | ||||||||||||
Net income (loss) attributable to partners | $ | 565.9 | $ | 66.7 | $ | 54.7 | $ | (132.4 | ) | $ | 554.9 | ||||||||
131
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Condensed Consolidating Statements of Cash Flows | |||||||||||||||||||
Year Ended September 30, 2012 | |||||||||||||||||||
(in millions) | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Cash flows from operating activities | $ | — | $ | 106.3 | $ | 132.7 | $ | — | $ | 239.0 | |||||||||
Cash flows from investing activities | |||||||||||||||||||
Acquisitions, net of cash acquired | — | (32.5 | ) | — | — | (32.5 | ) | ||||||||||||
Purchases of property, plant and equipment | — | (48.1 | ) | (220.6 | ) | — | (268.7 | ) | |||||||||||
US Salt, LLC contribution, net | — | 107.7 | (107.7 | ) | — | — | |||||||||||||
Payments associated with the disposal of retail propane operations | — | (58.1 | ) | — | (58.1 | ) | |||||||||||||
Other | — | 8.7 | — | — | 8.7 | ||||||||||||||
Net cash used in investing activities | — | (22.3 | ) | (328.3 | ) | — | (350.6 | ) | |||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Proceeds from the issuance of long-term debt | 255.0 | 1,159.2 | 509.9 | — | 1,924.1 | ||||||||||||||
Principal payments on long-term debt | (255.0 | ) | (1,221.6 | ) | (348.4 | ) | — | (1,825.0 | ) | ||||||||||
Distributions paid | (425.6 | ) | (267.9 | ) | (163.3 | ) | 588.9 | (267.9 | ) | ||||||||||
Distributions paid to non-controlling partners | — | — | (14.6 | ) | — | (14.6 | ) | ||||||||||||
Distributions received | 425.6 | 163.3 | — | (588.9 | ) | — | |||||||||||||
Net proceeds from the issuance of common units | — | — | 292.4 | — | 292.4 | ||||||||||||||
US Salt, LLC contribution, net | — | 74.8 | (74.8 | ) | — | — | |||||||||||||
Other | (0.1 | ) | (3.2 | ) | (5.6 | ) | — | (8.9 | ) | ||||||||||
Net cash provided by (used in) financing activities | (0.1 | ) | (95.4 | ) | 195.6 | — | 100.1 | ||||||||||||
Net decrease in cash | (0.1 | ) | (11.4 | ) | — | — | (11.5 | ) | |||||||||||
Cash at beginning of period | 3.0 | 8.5 | — | — | 11.5 | ||||||||||||||
Cash at end of period | $ | 2.9 | $ | (2.9 | ) | $ | — | $ | — | $ | — | ||||||||
132
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
Note 16. Quarterly Financial Data (Unaudited)
Inergy's business is seasonal due to weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather sensitive. Summarized unaudited quarterly financial data is presented below (in millions, except per unit information):
Quarter Ended | ||||||||||||||||
December 31 | March 31 | June 30 | September 30 | |||||||||||||
Fiscal 2012 | ||||||||||||||||
Revenues | $ | 668.6 | $ | 662.4 | $ | 371.6 | $ | 304.2 | ||||||||
Operating income | 48.1 | 66.5 | 6.6 | 13.3 | ||||||||||||
Net income (loss) | (3.6 | ) | 44.0 | (17.7 | ) | 543.2 | (b) | |||||||||
Net income (loss) attributable to partners | (4.0 | ) | 40.7 | (21.8 | ) | 540.0 | ||||||||||
Net income (loss) per limited partner unit:(a) | ||||||||||||||||
Basic | $ | (0.01 | ) | $ | 0.33 | $ | (0.15 | ) | $ | 4.18 | ||||||
Diluted | $ | (0.03 | ) | $ | 0.31 | $ | (0.17 | ) | $ | 4.10 | ||||||
Fiscal 2011 | ||||||||||||||||
Revenues | $ | 596.0 | $ | 720.5 | $ | 388.7 | $ | 448.6 | ||||||||
Operating income (loss) | 71.7 | 113.4 | (8.9 | ) | (21.7 | ) | ||||||||||
Net income (loss) | 38.5 | 36.6 | (35.5 | ) | (50.2 | ) | ||||||||||
Net income (loss) attributable to partners | 66.7 | 36.6 | (35.5 | ) | (50.2 | ) | ||||||||||
Net income (loss) per limited partner unit:(a) | ||||||||||||||||
Basic | $ | 0.82 | $ | 0.33 | $ | (0.32 | ) | $ | (0.42 | ) | ||||||
Diluted | $ | 0.72 | $ | 0.30 | $ | (0.32 | ) | $ | (0.42 | ) | ||||||
(a) | The accumulation of basic and diluted net income (loss) per limited partner unit does not total the amount for the fiscal year due to changes in ownership percentages throughout the year. |
(b) | The Company recorded a gain of $589.5 million during the quarter ended September 30, 2012 related to the disposition of its retail propane operations. |
Note 17. Subsequent Events
The Company has identified subsequent events requiring disclosure through the date of the filing of this Form 10-K.
On November 14, 2012, Inergy paid a quarterly distribution of $0.290 per limited partner unit to unitholders of record on November 7, 2012.
On November 5, 2012, Inergy Midstream announced the planned acquisition of 100% of the ownership interest of Rangeland Energy, LLC ("Rangeland") in exchange for $425 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments. The acquisition is planned to close during December 2012. Inergy Midstream has already entered into an agreement to sell $225 million through a private placement of common units to qualified institutional investors conditioned upon and closing contemporaneously with the closing of the Rangeland acquisition.
The primary purpose of this acquisition is to acquire the crude oil loading terminal, storage facility, and interconnecting pipeline assets of Rangeland, which are located in Northwestern North Dakota. Inergy Midstream's valuation of the assets acquired and liabilities assumed has not been completed as the acquisition has not closed to date. Inergy Midstream expects the significant components of the valuation to include property, plant and equipment, intangible contract assets and goodwill.
133
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
The following represents the pro forma consolidated statements of operations as if Rangeland had been included in the consolidated results of the Company for the year ended September 30, 2012 (in millions):
(Unaudited) Pro Forma Consolidated Statement of Operations | |||
Year Ended September 30, 2012 | |||
Revenue | $ | 2,010.2 | |
Net Income | $ | 507.6 | |
These amounts are based on certain assumptions made as to the purchase accounting of the transaction. A final determination of the purchase accounting adjustments, including the allocation of the purchase price of the assets acquired and liabilities assumed based on their fair values, has not been made. Accordingly, the purchase accounting adjustments made in connection with the development of the unaudited pro forma are preliminary and subject to material change. Rangeland was a development stage entity (as defined by ASC Topic 915, Development Stage Entities) until recently, and began principal commercial operations during June 2012, additionally revenues and earnings for the acquired company are insignificant for the years ended September 30, 2011 and 2010 and thus are not presented. The acquisition is planned to close during December 2012, however the Company provides no assurance regarding the timing or completion of the acquisition and additionally the amounts above are subject to change.
134
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
INERGY, L.P. | |||
By Inergy GP, LLC | |||
(its general partner) | |||
Dated: | November 20, 2012 | By | /s/ JOHN J. SHERMAN |
John J. Sherman, Chief Executive Officer | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following officers and directors of Inergy GP, LLC, as general partner of Inergy, L.P., the registrant, in the capacities and on the dates indicated.
Date | Signature and Title | |
November 20, 2012 | /S/ JOHN J. SHERMAN John J. Sherman, Chief Executive Officer and Director (Principal Executive Officer) | |
November 20, 2012 | /S/ MICHAEL J. CAMPBELL Michael J. Campbell, Senior Vice President and Chief Financial Officer (Principal Financial Officer) | |
November 20, 2012 | /S/ MICHAEL D. LENOX Michael D. Lenox, Vice President and Chief Accounting Officer (Principal Accounting Officer) | |
November 20, 2012 | /S/ PHILLIP L. ELBERT Phillip L. Elbert, Executive Vice President - Strategy Director) | |
November 20, 2012 | /S/ WARREN H. GFELLER Warren H. Gfeller, Director | |
November 20, 2012 | /S/ ARTHUR B. KRAUSE Arthur B. Krause, Director | |
November 20, 2012 | /S/ ROBERT D. TAYLOR Robert D. Taylor, Director | |
135
Schedule I
Inergy, L.P.
Parent Only
Condensed Balance Sheets
(in millions, except unit information)
September 30, | |||||||
2012 | 2011 | ||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 2.9 | $ | 3.0 | |||
Total current assets | 2.9 | 3.0 | |||||
Goodwill | 20.2 | 20.2 | |||||
Investment in subsidiaries | 1,380.6 | 3,021.6 | |||||
Total assets | $ | 1,403.7 | $ | 3,044.8 | |||
Liabilities and partners’ capital | |||||||
Current liabilities: | |||||||
Accrued expenses | $ | 2.7 | $ | 32.7 | |||
Current portion of long-term debt | 1.9 | 7.4 | |||||
Total current liabilities | 4.6 | 40.1 | |||||
Long-term debt, less current portion | 324.8 | 1,833.3 | |||||
Other long-term liabilities | 28.1 | 25.4 | |||||
Partners’ capital: | |||||||
Limited partner unitholders (125,795,836 and 119,147,858 common units issued and outstanding at September 30, 2012 and September 30, 2011, respectively, and 5,882,105 and 12,165,499 Class B units issued and outstanding at September 30, 2012 and September 30, 2011, respectively) | 1,046.2 | 1,146.0 | |||||
Total partners’ capital | 1,046.2 | 1,146.0 | |||||
Total liabilities and partners’ capital | $ | 1,403.7 | $ | 3,044.8 | |||
See accompanying notes to condensed financial statements.
136
Schedule I
Inergy, L.P.
Parent Only
Condensed Statements of Operations
(in millions)
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Operating income | $ | — | $ | — | $ | — | |||||
Other income (expense): | |||||||||||
Interest expense, net | (81.8 | ) | (113.5 | ) | (91.5 | ) | |||||
Gain on disposal of retail propane operations | 589.5 | — | — | ||||||||
Loss on Suburban Propane Partners, L.P. units | (47.6 | ) | — | — | |||||||
Early extinguishment of debt | (26.6 | ) | (52.1 | ) | — | ||||||
Equity in net income of subsidiary | 132.4 | 155.0 | 137.9 | ||||||||
Net income (loss) | $ | 565.9 | $ | (10.6 | ) | $ | 46.4 | ||||
See accompanying notes to condensed financial statements.
137
Schedule I
Inergy, L.P.
Parent Only
Condensed Statements of Comprehensive Income
(in millions)
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Net income (loss) | $ | 565.9 | $ | (10.6 | ) | $ | 46.4 | ||||
Change in unrealized fair value on cash flow hedges | (8.2 | ) | (11.1 | ) | (6.6 | ) | |||||
Comprehensive income (loss) | $ | 557.7 | $ | (21.7 | ) | $ | 39.8 | ||||
See accompanying notes to condensed financial statements.
138
Schedule I
Inergy, L.P.
Parent Only
Condensed Statements of Cash Flows
(in millions)
Year Ended September 30, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Cash flows from operating activities | $ | — | $ | — | $ | — | |||||
Cash flows from investing activities | — | — | — | ||||||||
Cash flows from financing activities: | |||||||||||
Proceeds from the issuance of long-term debt | 255.0 | — | 3.5 | ||||||||
Principal payments on long-term debt | (255.0 | ) | — | (6.2 | ) | ||||||
Distributions paid | (425.6 | ) | (311.6 | ) | (242.8 | ) | |||||
Distributions received | 425.6 | 311.6 | 242.8 | ||||||||
Other | (0.1 | ) | (0.6 | ) | 6.2 | ||||||
Net cash provided by (used in) financing activities | (0.1 | ) | (0.6 | ) | 3.5 | ||||||
Net increase (decrease) in cash | (0.1 | ) | (0.6 | ) | 3.5 | ||||||
Cash at beginning of period | 3.0 | 3.6 | 0.1 | ||||||||
Cash at end of period | $ | 2.9 | $ | 3.0 | $ | 3.6 | |||||
See accompanying notes to condensed financial statements.
139
Schedule I
Inergy, L.P.
Parent Only
Notes to Condensed Financial Statements
Note 1. Basis of Presentation
In the parent-only financial statements, the Company's investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of acquisition. The Company's share of net income of its unconsolidated subsidiaries is included in consolidated income using the equity method. The parent-only financial statements should be read in conjunction with the Company's consolidated financial statements.
140
Schedule II
Inergy, L.P. and Subsidiaries
Valuation and Qualifying Accounts
(in millions)
Year Ended September 30, | Balance at beginning of period | Charged to costs and expenses | Other Additions | Deductions (write-offs) | Balance at end of period | ||||||||||||||
Allowance for doubtful accounts | |||||||||||||||||||
2012 | $ | 0.2 | $ | — | $ | 0.2 | $ | — | $ | 0.4 | |||||||||
2011 | 0.2 | 0.1 | — | (0.1 | ) | 0.2 | |||||||||||||
2010 | 0.3 | (0.1 | ) | — | — | 0.2 | |||||||||||||
141