OUR PRIME POSITION
DELIVERING RESULTS NAVIGATING THE JOURNEY
INERGY, L.P. 2009 ANNUAL REPORT
THE INERGY FAMILY
OF COMPANIES
Total Gross Profi t
$ IN MILLIONS
397
457
502
574
IN A PRIME POSITION FOR INVESTORS
With two separate, publicly traded securities listed on the Nasdaq
Global Select stock market, Inergy, L.P. (NRGY) and Inergy Holdings,
L.P. (NRGP) offer investors two distinct ways to invest in Inergy’s
FY’06
FY’07
FY’08
FY’09
strategic objectives.
Adjusted EBITDA(a)
$ IN MILLIONS
175
211
239
297
FY’06
FY’07
FY’08
FY’09
NRGY Cash Distribution Paid
$ PER LIMITED PARTNER UNIT
2.14
2.28
2.44
2.60
2.70
Inergy, L.P. (“Inergy”) is a diversifi ed energy
Inergy Holdings, L.P. (“Inergy Holdings”),
infrastructure and distribution company.
also headquartered in Kansas City, Missouri,
Headquartered in Kansas City, Missouri,
controls the general partners of Inergy,
the Company’s propane operations serve
and its assets consist solely of its
approximately 700,000 retail customers,
ownership interests in Inergy, including
while also providing a variety of valuable
limited partnership interests and incentive
services to independent propane dealers
distribution rights. Inergy Holdings’
and multi-state marketers across
primary objective is to increase distributable
the United States. Inergy’s midstream
cash fl ow to its unitholders through
operations include a natural gas and
ownership of partnership interests in Inergy.
liquefi ed petroleum gas (“LPG”) storage
The Company’s management team is
business in New York, an industry-leading
aligned with the unitholders of both
FY’06
FY’07
FY’08
FY’09
CA(b)
solution mining and salt production
Inergy Holdings and Inergy. They base
NRGP Cash Distribution Paid
$ PER LIMITED PARTNER UNIT
company in New York, and a natural gas
all decisions on the best way to maximize
liquids (“NGL”) business in California.
value for the combined company’s unitholders.
Inergy’s objective is to increase distributable
1.23
1.77
2.29
2.86
3.40
cash fl ow to its unitholders through the
Company’s dual platform operating strategy.
FY’06
FY’07
FY’08
FY’09
CA(b)
COMPANY PROFILE
(a) EBITDA is defi ned as income (loss) before taxes, plus net
interest expense (inclusive of write-offs of deferred fi nancing
costs) and depreciation and amortization expenses. Adjusted
EBITDA represents EBITDA excluding (1) non-cash gains
or losses on derivative contracts associated with fi xed price
sales to retail propane customers, (2) long-term incentive
(one-time conversion bonuses) and equity compensation
expense, and (3) gains or losses on disposal of property,
plant, and equipment. Please refer to the Companies’ SEC
fi lings for further clarifi cation.
(b)Current Annualized
Navigating the journey. As a result of its dual platform operating strategy, Inergy has
grown from a standing start in 1996 to almost $1.6 billion in revenue and a combined
enterprise value of more than $4.0 billion. The Company operates in 28 states and employs
approximately 3,000 associates. It is the fi fth-largest propane retailer in the United States
and has built a respected transportation, supply, and logistics business. At the same
time – through its expansion into midstream operations – Inergy has become the largest
independent natural gas storage operator in the Northeast and has built a signifi cant
natural gas liquids business in California. Since its inception, Inergy has successfully
completed more than 84 acquisitions.
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INERGY OPERATIONS AT A GLANCE
Delivering results. We have built a solid foundation for future growth in both our propane and midstream energy business
platforms. Our signifi cant propane operations are geographically diversifi ed among the highest quality propane markets
across the eastern half of the United States, which diminishes the impact of weather on the company’s operations. Within
our midstream operations, we have become the largest independent natural gas storage operator in the northeastern
United States, situated near the Northeast demand center and atop the Marcellus Shale play, where we are establishing
an integrated storage hub. In addition, we own an industry-leading solution mining and salt production company that
is complementary to Inergy’s energy storage platform, and we have a signifi cant natural gas liquids business that is
strategically located between major refi ning centers on the West Coast.
PROPANE
RETAIL LOCATIONS
Inergy serves approximately 700,000
retail customers from more than 300
retail branches. These facilities are
located in the highest quality propane
markets and operate under a number of
regional brand names.
STEUBEN
NATURAL GAS STORAGE FACILITY
Steuben Gas Storage, located in Steuben
County, N.Y., has 6.2 Bcf of working gas
storage capacity that is 100% fee-based
under term contracts.
STAGECOACH
NATURAL GAS STORAGE FACILITY
Located approximately 150 miles northwest
of New York City, Stagecoach is the
closest natural gas storage facility to the
northeast market and anchors Inergy’s
gas storage platform.
FINGER LAKES
LIQUID PETROLEUM GAS STORAGE FACILITY
Expected to be in-service in mid 2010,
Finger Lakes Storage will encompass our
existing Bath Storage operations with
an expected capacity of up to 6.7 million
barrels of salt cavern storage.
THOMAS CORNERS
NATURAL GAS STORAGE DEVELOPMENT
Located in Steuben County, N.Y., the
Thomas Corners’ expansion will grow
to 7.0 Bcf of working gas capacity and
provide connections to the Tennessee
Gas Pipeline (TGP), Millennium and
Corning Natural Gas pipelines. It is 100%
contracted under long term agreements.
US SALT
SOLUTION MINDING
AND SALT PRODUCTION
US Salt, located in Watkins Glen, N.Y., is
an industry-leading solution mining and
salt production company that offers Inergy
additional development opportunities for
natural gas or LPG storage.
WEST COAST
NATURAL GAS LIQUIDS OPERATION
INERGY
CORPORATE OFFICE
Inergy’s West Coast NGL facility in the San
Joaquin Valley outside Bakersfi eld, Calif., offers
fractionation, storage, transportation and
isobutane production to major refi ners and
integrated oil companies on the West Coast.
Inergy’s corporate headquarters are located
in Kansas City, MO.
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DEAR FELLOW
UNITHOLDERS
JOHN J. SHERMAN
President and CEO
Diversifi cation of
Adjusted EBITDA
IN PERCENT
PROPANE
83
78
68
72
61
As I wrote this letter a year ago, we were in the midst of signifi cant turmoil
in the capital markets; and the broader economy was under enormous
downward pressure. At that time, we communicated to you that our business
fundamentals were strong and we were very focused on the things we could
control. We believed that 2009 presented Inergy with the opportunity to
distinguish itself.
FY’06
FY’07
FY’08
FY’09
CA(a)
Inergy was built to deliver consistent performance on behalf of investors
MIDSTREAM
17
22
32
28
39
in a variety of economic environments. Our underlying businesses –
both propane distribution and natural gas storage and transport – are
characterized by stable, recession-resistant cash fl ows and growth potential.
In the recent challenging economic and capital markets environment, we
FY’06
FY’07
FY’08
FY’09
CA(a)
stayed the course for our unitholders.
(a) Forecast 2010 Run Rate
ot tliub saw ygrenI “
deliver consistent
performance on
behalf of investors in
a variety of economic
environments.”
In 2009, we:
• achieved our fi nancial performance objectives, increased our earnings
guidance mid-year, and grew cash earnings by 24% over the prior year;
• increased cash distributions each quarter at both NRGY and NRGP;
• raised $400 million in long-term growth capital in a choppy capital
markets environment;
• kept our current capital expansion projects on track; and
• expanded our future growth outlook with the announcement of multiple
high-return capital investment opportunities.
As a result of our consistent performance and our strong fi nancial position,
we are situated better than ever to take advantage of the opportunities that
lie ahead.
MAJOR STEPS IN THE MIDSTREAM BUSINESS
Following are the highlights of activity in our midstream
Inergy has grown to become the largest independent
business in 2009:
natural gas storage operator in the northeastern
United States. Our strategy is focused on adding stable
Stagecoach Natural Gas Storage - This is our fl agship
cash fl ows without commodity price exposure. Our
asset anchoring Inergy’s natural gas storage infrastructure
asset base consists of high-quality assets that can be
in the Northeast. With its strategic location – 150 miles
expanded through high-return capital investments.
northwest of New York City – it serves one of the largest
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Over the last fi ve years,
through strategic
acquisitions and
NRGY
INVESTMENT HIGHLIGHTS
subsequent expansion,
● Attractive yield and growth potential
Inergy has built a
very valuable natural
gas storage and
● Strong track record of distribution growth
● Tax-advantaged distributions to unitholders
transportation business
● Large portfolio of high-return organic projects
in the Northeast U.S.
These strategically
located assets are all
within a 40-mile radius of
one another and within
200 miles of New York
City. We are currently
NRGP
● Higher growth – lower current yield
● Tax-advantaged distributions to unitholders
● As NRGY grows distributions, NRGP’s cash
fl ow increases
● NRGP has among the highest leverage-to-growth
executing a strategy to
ratios of public GPs
expand storage capacity,
transportation capacity,
energy-demand centers
in the United States, has
26.5 Bcf of working gas
capacity, and is connected
to major interstate gas
pipelines. The steady
performance delivered
from this asset in 2009
underpins our ability
to deliver solid results
to unitholders.
Thomas Corners - Located
in Steuben County, our
Thomas Corners Storage
operation was recently
placed into service ahead
of schedule and under
budget. With 7 Bcf of
and connectivity. Ultimately, we plan to operate
capacity, it will provide connections to the Tennessee
these distinct assets as an integrated storage and
Gas Pipeline (TGP), Millennium, and Corning Natural Gas
transportation hub. This signifi cant opportunity has
pipelines. Its capacity is 100 percent contracted.
been enhanced by the development of the Marcellus
Shale. We serve gas utilities, gas marketers, and local
Steuben Gas Storage Company - Acquired in the 2007
producers providing unmatched fl exibility for accessing
Arlington Storage acquisition, Steuben Gas Storage is
multiple supply sources and premium demand markets.
also located in Steuben County, N.Y., and currently has
We couldn’t be more excited about our potential in
steady performer and is fully contracted with high-quality
the Northeast. Our cash earnings from this segment
customers. Steuben Gas Storage has future earnings
are expected to double over the next two years
growth potential because of its planned connectivity
without acquisition. We continue working on multiple
to Thomas Corners, TGP, and the Millennium Pipeline.
6.2 Bcf of working gas capacity. This operation has been a
opportunities that could enhance our growth rate.
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US Salt - Located in Schuyler County, N.Y., between
Stagecoach and our Steuben County natural gas storage
facilities, US Salt has quickly proven to be an excellent
investment for Inergy. In addition to its profi table salt
production business – selling high-quality, high-margin
food, pharmaceutical, and chemical feedstock-grade
salt each year – the solution mining process creates salt
caverns that can be developed into natural gas and/or
natural gas liquids storage. US Salt provides us with an
ongoing pipeline of storage development opportunities
at economics that give us a competitive advantage.
Finger Lakes - Adjacent to US Salt in Watkins Glen,
N.Y., we are currently developing our new Finger Lakes
storage operation. Along with our current Bath LPG
storage facility in operation, it can hold up to 6.7 million
Inergy’s Steuben natural gas storage facility currently has 6.2 Bcf of working
gas storage capacity. Here two employees discuss operations in front of the
compressor unit.
barrels of LPG and is expected to be in-service in mid
Project. When completed, these two projects will allow
2010. Offering connectivity to the Teppco Pipeline, as
shippers to transport gas bi-directionally approximately
well as rail and truck access, Finger Lakes will primarily
75 miles between the Millennium Pipeline in Tioga
operate under long-term contracts with investment-
County, N.Y., and Transcontinental Gas Pipeline
grade anchor tenants.
Corporation’s (“Transco”) Leidy Line in Columbia
County, Pa., and all points in between.
West Coast - Strategically located near Bakersfi eld,
Calif., between major refi ning centers, our West Coast
The response to our open season is yet another
NGL operation completed a major capital expansion
validation of our strategy to build out the hub in the
project in July. The West Coast operation encompasses
Northeast. This geography is characterized by increasing
storage, fractionation, rail/truck terminaling, and a
supply, increasing demand, and inadequate natural
recently added butane isomerization unit that provides
gas infrastructure. Inergy is very well positioned to take
services to West Coast refi ners for gasoline blending.
advantage of this opportunity.
In addition, the operation has 24 million gallons of
NGL storage.
Marc 1 Hub line and North-South Projects - We are
currently moving forward with the development of
our MARC I Hub Line and our North-South Projects.
In response to a recent open season, Inergy received
indications of interest exceeding 400 percent of the
capacity required to construct the 43-mile Marc I Hub
Line and indications of interest exceeding 600 percent
of the capacity required to construct the North-South
INTEGRATED NORTHEAST STORAGE AND TRANSPORTATION HUB
Inergy is strategically positioned as the largest independent natural gas storage
operator in the northeastern United States. In the heart of the Marcellus Shale play,
our midstream operations have the combined potential for expansion to over 50 Bcf
of working gas storage capacity. All of Inergy’s natural gas storage operations are
within a 40-mile radius of one another, providing an ability to connect all of the
facilities together in an integrated storage and transportation hub, further enhancing
the strategic opportunity of our midstream assets.
Enlarged graphic shows detail
of highlighted states.
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STEUBEN
NATURAL GAS
STORAGE FACILITY
6.2 BCF
THOMAS CORNERS
NATURAL GAS
STORAGE FACILITY
7.0 BCF
FINGER LAKES
LIQUEFIED PETROLEUM
GAS STORAGE FACILITY
6.7M BBL
US SALT
SALT PRODUCTION/GAS
STORAGE DEVELOPMENT
10.0 BCF
STAGECOACH
NATURAL GAS
STORAGE FACILITY
26.5 BCF
MARC 1 HUB LINE
NATURAL GAS
PIPELINE DEVELOPMENT
43 MILES
MARCELLUS SHALE
NATURAL GAS
FORMATION
489 TCF
Estimated Recoverable Natural Gas
NEW YORK
INERGY PIPELINES
STAGECOACH NORTH/SOUTH LATERALS
EXISTING STORAGE LATERALS
MARC I HUB LINE (PROPOSED)
PENNSYLVANNIA
INDUSTRY PIPELINES
DOMINION
TENNESSEE GAS PIPELINE (TGP)
MILLENNIUM
EMPIRE/EMPIRE CONNECTOR
NATIONAL FUEL
TRANSCO
NEVADA
CALIFORNIA
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INERGY WEST COAST OPERATIONS
LOCATION: Bakersfi eld, California
Inergy’s North Coles Levee facility is in the San Joaquin Valley,
and offers fractionation, storage, transportation and isobutane
production services to the California energy market.
GAS PLANTS
REFINERIES
WEST COAST NGL OPERATIONS
Inergy’s West Coast natural gas liquids (NGL) business located in Southern California near Bakersfi eld recently
completed a major capital expansion project that has solidifi ed Inergy’s position as one of North America’s
leading marketers of NGL products. With a goal of providing refi ners and producers with a range of services
that include NGL storage, transportation, fractionation and marketing services, Inergy helps them optimize
their assets. A new butane isomerization unit, together with a new refrigerated butane storage facility,
insulates refi ners from costly seasonal imports and exports.
PROPANE INDUSTRY LEADERSHIP
The successful execution of our midstream strategy has
Our propane operations once again delivered outstanding
resulted in a material upgrade to the diversifi cation of our
results while continuing to develop our industry-leading
cash fl ows. Our Northeast natural gas assets generate the
platform. Profi t margins improved, and we operated
highest quality of earnings in the entire MLP sector. These
more effi ciently throughout our geographic footprint.
assets are coveted by customers, competitors, and major
Our primary focus on the residential segment, which we
investors. We believe that the markets have just begun to
believe to be the most stable and profi table business
understand the potential of what we are building.
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segment, differentiates us as a defensive, recession-
resistant investment.
The investment in our natural gas liquids supply and
transportation business unit, continues to enhance
our competitive position. 2009 was a year in which we
experienced wholesale price volatility as well as regional
supply disruptions. The teamwork exhibited across the
organization ensured a secure, cost-effective supply
giving us a competitive advantage while adding to
profi tability. We expect additional synergies with our
Finger Lakes LPG and West Coast midstream operations
that will further strengthen this business unit’s contribution
going forward.
Our propane operations continue to grow through
a selective and disciplined acquisition process. The
Inergy’s propane operations primarily serve residential customers across the
eastern half of the United States. Residential customers are the most stable
and profi table customer segment in the propane industry.
industry remains fragmented. We should continue to
Our propane operations provide you with long-term, stable,
see consolidation, and you should expect Inergy to
and economic cycle-resistant cash fl ows. We have a “best in
be a major participant in ways that are accretive to
class” propane operating team that knows how to optimize
our investors.
long-term earnings for our investors.
A PRIME POSITION FOR FUTURE GROWTH
Our management team and workforce get better every day,
At this writing, our country appears to be emerging
and we are very focused on achieving our short-term and
from one of the most diffi cult years on record. Thanks
long-term objectives on your behalf. We understand that
to the relentless execution of our dual platform growth
you have high expectations, and we take that very seriously.
strategy, we have completed Fiscal 2009 with not just
As you know, we are signifi cant investors alongside you.
record results, but in a better position for growth now
than at any time in our history. We have ample balance
sheet liquidity and the proven ability to raise cost-
effective capital for expansion.
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INERGY’S EXECUTIVE MANAGEMENT TEAM
(LEFT TO RIGHT): Carl Hughes, Andy Atterbury,
John Sherman, Laura Ozenberger, Phil Elbert,
Bill Moler, Brooks Sherman
Looking forward, I expect us to:
• further establish Inergy as a premium service provider in core midstream
markets;
eht ot sknahT “
relentless execution
of our dual platform
growth strategy, we
have completed fi scal
2009 with not just
record results, but
in a better position
for growth now
than at any time
in our history.”
• continue to improve and develop our industry-leading propane franchise;
• execute disciplined growth in both businesses, focusing on high-quality,
high-economic return opportunities;
• maintain our strong and fl exible fi nancial position so we are positioned to
execute on good opportunities;
• retain, recruit, and reward talent – we must have the best team to execute for
investors; and
• emphasize and practice safety in all that we do.
Thank you again for your confi dence and trust. We take our responsibilities
to you very seriously. We look forward to a bright future and to meeting
your expectations.
Sincerely,
John J. Sherman
President and CEO
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2009
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: 000-32453
INERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
43-1918951
(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 NASDAQ Global Select National Market
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 È 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 È
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 È 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 during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes ‘ No ‘
Indicate by check mark 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. È
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 È
Non-accelerated filer ‘ (Do not check if a smaller reporting company)
Accelerated filer ‘
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 È
The aggregate market value of the 59,809,587 common units of the registrant held by non-affiliates computed by reference to the $30.97
closing price of such common units on October 30, 2009, was $1.9 billion. The aggregate market value of the 50,177,451 common units of the
registrant held by non-affiliates computed by reference to the $21.92 closing price of such common units on March 31, 2009, the last business
day of the registrant’s most recently completed second fiscal quarter, was $1.1 billion. As of November 16, 2009, the registrant had
59,817,087 common units outstanding.
Portions of the following documents are incorporated by reference into the indicated parts of this report: None.
DOCUMENTS INCORPORATED BY REFERENCE
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 company,” “Inergy,” or “Inergy, L.P.,” we are referring
either to Inergy, L.P., the registrant itself, or to Inergy, L.P. and its operating subsidiaries collectively, as the
context requires.
(2) When we use the term “our predecessor,” we are referring to Inergy Partners, LLC, the entity that
conducted our business before our initial public offering, which closed on July 31, 2001. Inergy, L.P. was
formed as a Delaware limited partnership on March 7, 2001 and did not have operations until the closing of
our initial public offering. Our predecessor commenced operations in November 1996. The discussion of
our business throughout this report relates to the business operations of Inergy Partners, LLC before Inergy,
L.P.’s initial public offering and of Inergy, L.P. thereafter.
(3) 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.
(4) When we use the term “finance company” we are referring to Inergy Finance Corp., a subsidiary of
Inergy, L.P., formed on September 21, 2004.
(5) When we use the term “managing general partner,” we are referring to Inergy GP, LLC.
(6) When we use the term “non-managing general partner,” we are referring to Inergy Partners, LLC.
(7) When we use the term “general partners,” we are referring to our managing general partner and our
non- managing general partner.
(8) When we use the term “Inergy Holdings” we are referring to Inergy Holdings, L.P. (NASDAQ
symbol “NRGP”) itself, or to Inergy Holdings, L.P. and its subsidiaries collectively, as the context requires.
• We have a managing general partner and a non-managing general partner. Our managing general partner
is responsible for the management of our company and its operations are governed by a board of
directors. Our managing general partner does not have rights to allocations or distributions from our
company and does not receive a management fee, but it is reimbursed for expenses incurred on our
behalf. Our non-managing general partner owns a 0.8% non-managing general partner interest in our
company.
INERGY, L.P.
INDEX TO ANNUAL REPORT ON FORM 10-K
PART I
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART II
Item 5. Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases
of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . .
Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13. Certain Relationships, Related Transactions and Director Independence . . . . . . . . . . . . . . . . . . .
Item 14.
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
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Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Item 1. Business.
Recent Developments
PART I
On November 24, 2009, we entered into a secured credit facility which provides borrowing capacity of up to
$525 million in the form of a $450 million general partnership credit facility and a $75 million working capital
credit facility. This facility replaces our former senior credit facility due 2010. This new facility will mature on
November 22, 2013. Borrowings under this new facility 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.
The new secured credit facility contains various affirmative and negative covenants and default provisions, as
well as requirements with respect to the maintenance of specified financial ratios and limitations on making
investments, permitting liens and entering into other debt obligations. All borrowings under the facility 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 1.50% to
2.75%; or
the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.50% to
3.75%.
•
•
General
Inergy, L.P., a publicly traded Delaware limited partnership, was formed on March 7, 2001 and we closed on our
initial public offering on July 31, 2001. We own and operate a growing, geographically diverse retail and
wholesale propane supply, marketing and distribution business. We also own and operate a growing midstream
business that includes three natural gas storage facilities (“Stagecoach”, “Steuben” and “Thomas Corners”), a
liquefied petroleum gas (“LPG”) storage facility (“Bath”), a natural gas liquids (“NGL”) business and a solution-
mining and salt production company (“US Salt”). For the fiscal year ended September 30, 2009, we sold and
physically delivered 310.0 million gallons of propane to retail customers and 380.6 million gallons of propane to
wholesale customers.
We believe we are the fifth largest propane retailer in the United States based on retail propane gallons sold. Our
propane business includes the retail marketing, sale and distribution of propane, including the sale and lease of
propane supplies and equipment, to residential, commercial, industrial and agricultural customers. We market our
propane products under various regional brand names. As of October 30, 2009, we serve approximately 700,000
retail customers in 28 states from 312 customer service centers, which have an aggregate of 31.1 million gallons
of above-ground propane storage. In addition to our retail propane business, we operate a wholesale supply,
marketing and distribution business, providing propane procurement, transportation and supply and price risk
management services to our customer service centers, as well as to independent dealers, multistate marketers,
petrochemical companies, refinery and gas processors and a number of other NGL marketing and distribution
companies in 40 states, primarily in the Midwest, Northeast and South.
We also own and operate a midstream business which includes the following assets:
•
the Stagecoach natural gas storage facility, a high performance, multi-cycle natural gas storage facility
with 26.25 bcf of working gas capacity, a maximum withdrawal capability of 500 MMcf/day and a
maximum injection capability of 250 MMcf/day. Located 150 miles northwest of New York City, the
Stagecoach facility is the closest natural gas storage facility to the northeastern United States market.
Stagecoach is connected to Tennessee Gas Pipeline Company’s 300-Line and the newly constructed
Millennium pipeline. The facility is fee-based and is currently 100% contracted primarily with
investment grade-rated companies with term contracts having a weighted average maturity extending to
September 2014.
1
•
•
•
•
an NGL business near Bakersfield, California, which includes a 25.0 MMcf/day natural gas processing
plant, a 12,000 bpd NGL fractionation plant, an 8,000 bpd butane isomerization plant, NGL rail and
truck terminals, a 24.0 million gallon NGL storage facility and NGL transportation/marketing
operations.
the Bath LPG Storage Facility, a 1.7 million barrel salt cavern LPG storage facility located near Bath,
New York, approximately 210 miles northwest of New York City and 60 miles from our Stagecoach
facility. The facility is supported by both rail and truck terminals capable of loading/unloading 20 – 23
rail cars per day and 17 truck transports per day.
100% of the membership interests of Arlington Storage Company, LLC (“ASC”). ASC is the majority
owner and operator of the Steuben Gas Storage Company (“Steuben”), which owns a 6.2 bcf natural gas
storage facility located in Steuben County, New York.
our recently completed development of Thomas Corners, a 7 bcf natural gas storage facility also located
in Steuben County, New York. This facility was placed in service in November 2009.
• US Salt, an industry-leading solution mining and salt production company located in Schuyler County,
New York, between our Stagecoach and Steuben natural gas storage facilities. US Salt produces and
sells over 300,000 tons of salt each year. The solution mining process used by US Salt creates salt
caverns that can be developed into usable natural gas storage capacity.
We have grown primarily through acquisitions and to a lesser extent through organic expansion projects. Since
the inception of our predecessor in November 1996 through September 30, 2009, we have acquired 84 companies
for an aggregate purchase price of approximately $1.8 billion, including working capital, assumed liabilities and
acquisition costs. The acquisitions include the assets of three propane companies acquired during fiscal 2009 for
an aggregate purchase price, net of cash acquired, of $11.8 million.
The following chart sets forth information about each business we acquired during the fiscal year ended
September 30, 2009, and through the date of this filing:
Acquisition Date
October 2008
April 2009
June 2009
Company
Blu-Gas group of companies
Newton’s Gas Service, Inc.
F.G. White Company, Inc.
Location
Denver, NC
Colchester, VT
Waitsfield, VT
The address of our principal executive offices is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri,
64112 and our telephone number at this location is 816-842-8181. Our common units trade on the NASDAQ
Global Select National Market under the symbol “NRGY”. We electronically file certain documents with the
Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K (as appropriate), along with any related amendments and supplements. From
time-to-time, we also may file registration and related statements pertaining to equity or debt offerings. You may
read and download our SEC filings over the internet from several commercial document retrieval services as well
as at the SEC’s website at www.sec.gov. You may also read and copy our SEC filings at the SEC’s public
reference room located at 100 F. Street, N.E., Washington, D.C. 20549. Please call the SEC 1-800-SEC-0330 for
further information concerning the public reference room and any applicable copy charges. In addition, our SEC
filings are available at no cost after the filing thereof on our website at www.inergypropane.com. Please note that
any internet addresses provided in this Form 10-K are for information purposes only and are not intended to be
hyperlinks. Accordingly, no information found and/or provided at such internet addresses is intended or deemed
to be incorporated by reference herein.
2
Industry Background and Competition
Propane
Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source
recognized for its transportability and ease of use relative to alternative stand-alone energy sources. Our retail
propane business consists principally of transporting propane to our customer service centers and other
distribution areas and then to tanks located on our customers’ premises. Retail propane falls into four broad
categories: residential, industrial, commercial and agricultural. Residential customers use propane primarily for
space and water heating. Industrial customers use propane primarily as fuel for forklifts and stationary engines, to
fire furnaces, as a cutting gas, in mining operations and in other process applications. Commercial customers,
such as restaurants, motels, laundries and commercial buildings, use propane in a variety of applications,
including cooking, heating and drying. In the agricultural market, propane is primarily used for tobacco curing,
crop drying, poultry brooding and weed control.
Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during
the refining process. Propane is normally transported and stored in a liquid state under moderate pressure or
refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is
increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its
detection. Propane is clean-burning, producing negligible amounts of pollutants when consumed.
The retail market for propane is seasonal because it is used primarily for heating in residential and commercial
buildings. Approximately 70% of our retail propane volume is sold during the peak heating season from October
through March. Consequently, sales and operating profits are generated mostly in the first and fourth calendar
quarters of each calendar year.
Propane competes primarily with natural gas, electricity and fuel oil as an energy source, principally on the basis
of price, availability and portability. Propane is more expensive than natural gas on an equivalent BTU basis in
locations served by natural gas, but serves as an alternative to natural gas in rural and suburban areas where
natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into
traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail
distribution systems. Although the extension of natural gas pipelines tends to displace propane distribution in
areas affected, we believe that new opportunities for propane sales arise as more geographically remote
neighborhoods are developed. Propane is generally less expensive to use than electricity for space heating, water
heating, clothes drying and cooking. Although propane is similar to fuel oil in certain applications and market
demand, propane and fuel oil compete to a lesser extent than propane and natural gas, primarily because of the
cost of converting to fuel oil. The costs associated with switching from appliances that use fuel oil to appliances
that use propane are a significant barrier to switching. By contrast, natural gas can generally be substituted for
propane in appliances designed to use propane as a principal fuel source.
In addition to competing with alternative energy sources, we compete with other companies engaged in the retail
propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on
a local basis with other large full-service, multi-state propane marketers, smaller local independent marketers and
farm cooperatives. Based on industry publications, we believe that the 10 largest retailers account for 37% of the
total retail sales of propane in the United States and that no single marketer has a greater than 10% share of the
total retail market in the United States. Most of our customer service centers compete with several marketers or
distributors. Each customer service center operates in its own competitive environment because retail marketers
tend to locate in close proximity to customers. Our typical customer service center generally has an effective
marketing radius of approximately 25 miles, although in certain rural areas the marketing radius may be extended
by a satellite location.
The ability to compete effectively further depends on the reliability of service, responsiveness to customers and
the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more
3
comprehensive than many of our smaller, independent competitors and give us a competitive advantage over
such retailers. We also believe that our service capabilities and customer responsiveness differentiate us from
many of these smaller competitors. Our employees are on call 24-hours and seven-days-a-week for emergency
repairs and deliveries.
Retail propane distributors typically price retail usage based on a per gallon margin over wholesale costs. As a
result, distributors generally seek to maintain their operating margins by passing costs through to customers, thus
insulating themselves from volatility in wholesale propane prices.
The propane distribution industry is characterized by a large number of relatively small, independently owned
and locally operated distributors. Each year, a number of these local distributors have sought to sell their business
for reasons that include, among others, retirement and estate planning. In addition, the propane industry faces
increasing environmental regulations and escalating capital requirements needed to acquire advanced, customer-
oriented technologies. Primarily as a result of these factors, the industry is undergoing consolidation and we, as
well as other national and regional distributors, have been active consolidators in the propane market. In recent
years, an active, competitive market has existed for the acquisition of propane assets and businesses. We expect
this acquisition market to continue for the foreseeable future.
The wholesale propane business is highly competitive. Our competitors in the wholesale business include
producers and independent regional wholesalers. We believe that our wholesale supply and distribution business
provides us with a stronger regional presence and a reasonably secure, efficient supply base and positions us well
for expansion through acquisitions.
Midstream
We own, as part of our midstream operations, a high-performance, multi-cycle natural gas storage facility
(Stagecoach) in New York that we acquired in August 2005. We also own an NGL business in California, which
includes a 25.0 MMcf/day natural gas processing plant, a 12,000 bpd NGL fractionation plant, an 8,000 bpd
butane isomerization plant, NGL rail and truck terminals, a 24.0 million gallon NGL storage facility and NGL
transportation/marketing operations. We also own a 1.7 million barrel salt cavern liquefied petroleum gas storage
facility near Bath, New York. In October 2007, we acquired a controlling interest in Steuben Gas Storage
Company (“Steuben”), which owns a 6.2 bcf natural gas storage facility located in Steuben County, New York.
In August 2008, we acquired US Salt, an industry leading solution mining and salt production company located
in Schuyler County, New York. The solution mining process used by US Salt creates salt caverns that can be
developed into usable natural gas storage and LPG storage capacity. In November 2009, we completed our
development of Thomas Corners, a 7 bcf natural gas storage facility located in Steuben County, New York. We
believe these businesses complement our existing propane operations and provide us with added long-term
strategic benefits.
Natural Gas Storage Business
According to the Energy Information Administration’s consumption data, natural gas supplies approximately
25% of U.S. energy. In recent years, the market for natural gas has experienced increasingly volatile prices, due
in part to the following factors:
• weather-related demand shifts;
•
•
•
infrastructure constraints;
trading impacts on short-term energy markets; and
supply, demand and other factors affecting alternative fuels.
4
Underground natural gas storage facilities are a critical component of the North American natural gas
transmission and distribution system. They provide an essential reliability cushion against unexpected disruptions
in supply, transportation or markets and allow for the warehousing of gas to meet expected seasonal and daily
variability in demand. According to the Energy Information Administration, U.S. natural gas consumption is
expected to grow at a compound annual growth rate of 1.0% through 2020.
Most forecasts of North American natural gas supply and demand suggest a continuation of trends that will result
in increased demand for natural gas storage capacity. Seasonal and weather sensitive demand sectors (residential
and commercial heating demand and gas-fired power generation demand) have been growing and are expected to
continue to do so, while the less seasonal industrial demand has been declining. Natural gas supply, meanwhile,
has become almost entirely non-seasonal, requiring greater reliance on natural gas storage to respond to demand
variability. On average, total North American natural gas consumption levels are approximately 40% higher in
the winter months than summer months primarily due to the requirements of residential and commercial market
sectors. These markets are very temperature sensitive with demand being highly variable both on a seasonal and
a daily basis thus requiring that storage be capable of providing high maximum daily deliverability on the coldest
days when storage due to infrastructure constraints provides as much as 50% of the market’s total requirement.
Analysis has shown that seasonal winter demand has continued to show steady growth even though warmer
winter temperature trends have muted the full impact of this increasing demand. Gas storage has facilitated the
creation of a natural gas industry that is characterized by a production profile that is largely non-seasonal and a
consumption profile that is highly seasonal and weather sensitive. Natural gas storage is essential in reallocating
this inherent supply and demand imbalance.
In the natural gas storage business, there are significant barriers to entry, particularly in depleted reservoir storage
such as the Stagecoach facility. Barriers include:
Geology: rock quality, depth, containment and reservoir size heavily influence development
opportunities;
Geography: proximity to existing pipeline infrastructure, surface development and complicated land
ownership all combine to further increase the difficulty in developing and operating natural gas
storage facilities;
Specialized skills: finding and retaining qualified and skilled natural gas storage professionals is a
challenge in today’s competitive job market in the oil & gas sectors due to the specialized nature of
the skills required; and
Development costs: costs for new natural gas storage capacity development have continued to increase.
Although there are significant barriers to entry within the natural gas storage industry, competition is robust.
Competition for natural gas storage is primarily based on location, connectivity and the ability to deliver natural
gas in a timely and reliable manner. Our natural gas storage facilities compete with other means of natural gas
storage, including other depleted reservoir facilities, salt cavern storage facilities and liquefied natural gas and
pipelines.
Storage capacity is held by a wide variety of market participants for a variety of purposes such as:
Reliability: local distribution companies (“LDC’s”) hold the bulk of capacity and tend to use it in a
manner relatively insensitive to gas prices, injecting gas into storage during the summer to meet
fairly well-defined inventory targets and withdrawing it in winter to meet peak load requirements
while retaining a sufficient cushion of inventory to meet worst-case late winter demands. For such
customers with an obligation to serve core end use markets, the value of storage may be significantly
greater than the price differential between winter and summer gas. LDC’s will pay the price to
secure the natural gas storage they need up to the cost of alternatives (i.e., long haul pipeline
capacity or above-ground storage).
5
Efficiency: pipeline operators use storage capacity for system balancing requirements and to manage
maintenance schedules, as well as to provide storage services to shippers on their systems. Producers
use capacity to minimize production fluctuations and to manage market commitments. Power
generators use storage capacity to provide swing capability for their plants that experience high daily
and even hourly variability of requirements.
Arbitrage: energy merchants and other trading entities use storage for gas price arbitrage purposes,
buying and injecting gas at times of low gas prices and withdrawing at times of higher prices as
driven by the fundamentals of the natural gas market.
The value of natural gas storage is a reflection of its critical role in providing the North American natural gas
market with a degree of supply reliability, flexibility and seasonal and daily demand balancing.
NGL Business
In general, natural gas produced at the wellhead contains, along with methane, various NGLs. This raw natural
gas is usually not acceptable for transportation in the nation’s major natural gas pipeline systems or for
commercial use as a fuel. Our natural gas processing operation, located near Bakersfield, CA, separates, for the
most part, the NGLs from the methane and delivers the methane to the local natural gas pipelines. The NGLs are
retained for further processing within our fractionation facility.
NGL fractionation facilities separate mixed NGL streams into discrete NGL products: propane, normal butane,
isobutane and pentanes (sometimes referred to as natural gasoline). The three primary sources of mixed NGLs
fractionated in the United States are (i) domestic natural gas processing plants, (ii) domestic crude oil refineries
and (iii) imports of butane and propane mixtures. The mixed NGLs delivered from domestic natural gas
processing plants and crude oil refineries to our NGL fractionation facility are typically transported by NGL
pipelines, railcar and NGL transport truck.
Other businesses within our NGL operation are butane isomerization and refrigerated storage. Our recently
constructed isomerization facility chemically changes normal butane to isobutane, which we provide to area
refineries for motor fuel blending.
The purity NGL products (propane, normal butane, isobutane and natural gasoline) are typically 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. Some more common uses of isobutane is 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.
Our NGL business encounters competition from fully integrated oil companies and independent NGL market
participants. Each of our competitors has varying levels of financial and personnel resources and competition
generally revolves around price, service and location. The majority of our NGL processing and fractionation
activities are processing mixed NGL streams for third-party customers and to support our NGL marketing
activities under contractual and fee-based arrangements. These fees (typically 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 and transportation and NGL 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.
6
Salt Mining
According to the Salt Institute, a North American based non-profit salt industry trade association, more than
250 million metric tons of salt were produced in the world in 2007. China is the single largest producer of salt,
with 59.8 million metric tons, followed by the United States, with 44.5 million metric tons. 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. Our US Salt facility, located in Schuyler County, New York, produces salt
using solution mining and mechanical evaporation. The facility produces and sells over 300,000 tons of salt each
year.
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. The salt solution, or brine, is then pumped out and taken to a plant for evaporation.
At the plant, the brine is treated to remove minerals and pumped into vacuum pans, sealed containers in which
the brine is boiled and then evaporated until the salt is left behind. Then it is dried and refined. Depending on the
type of salt to be produced, iodine and an anti-clumping agent may be added to the salt. Most food grade table
salt is produced in this manner.
After the salt is removed from a solution-mined salt deposit, the empty cavern can be used to store other
substances, like natural gas, LPG or compressed air.
Our US Salt facility has existing cavern space that we are currently developing into a 5 million barrel LPG
storage facility that we expect to place into service in the spring of 2010. There is also existing cavern space that
we intend to convert to approximately 10 bcf of natural gas storage. With each new brine well that we drill we
create additional potential storage capacity.
Business Strategy
Our primary objective is to increase distributable cash flow for our unitholders, while maintaining the highest
level of commitment and service to our customers. We have engaged and will continue to engage in objectives of
further growth through acquisitions both in our propane and midstream operations, internally generated
expansion and measures aimed at increasing the profitability of existing operations.
Competitive Strengths
We intend to pursue this objective by capitalizing on what we believe are our competitive strengths as follows:
Proven Acquisition Expertise
Since our predecessor’s inception and through September 30, 2009, we have acquired and successfully integrated
84 companies—78 propane companies and 6 midstream businesses. Our executive officers and key employees,
who together average more than 15 years experience in the propane and midstream energy-related industries,
have developed business relationships with retail propane owners and businesses as well as other midstream
industry participants throughout the United States. These significant industry contacts have enabled us to
negotiate most of our acquisitions on an exclusive basis. We believe that this acquisition expertise should allow
us to continue to grow through strategic and accretive acquisitions. Our acquisition program will continue to
seek:
•
•
•
businesses that generate distributable cash flow that is accretive to common unitholders on a per unit
basis;
propane and midstream businesses in attractive market areas;
propane businesses with established names and reputations for customer service and reliability;
7
•
propane businesses with high concentration of propane sales to residential customers;
• midstream businesses that generate predictable, stable fee-based cash flow streams;
• midstream businesses with organic expansion opportunities or strategic regional enhancement; and
•
retention of key employees in acquired businesses.
Management Experience
Our senior management team has extensive experience in the propane and midstream energy industry. Our
management team has a proven track record of enhancing the value of our partnership, through the acquisition,
integration and optimization of the businesses we own and operate.
Flexible Financial Structure
We have a $350 million revolving credit facility for acquisitions and a $75 million revolving working capital
facility. These facilities include a provision which allows us to utilize up to $200 million of combined borrowing
capacity for working capital as needed during the winter heating season. We believe our available capacity under
these facilities combined with our ability to fund acquisitions and organic expansion projects through the
issuance of additional partnership interests will provide us with a flexible financial structure that will facilitate
our acquisition and organic expansion effort.
As discussed in Item 1, we now have a $450 million general partnership revolving credit facility for acquisitions,
capital expenditures and general partnership purposes and a $75 million revolving working capital facility.
Propane Business Strengths
Focus on High Percentage of Retail Sales to Residential Customers
Our retail propane operations concentrate on sales to residential customers. Residential customers tend to
generate higher margins and are generally more stable purchasers than other customers. For the fiscal year ended
September 30, 2009, sales to residential customers represented approximately 70% of our retail propane gallons
sold. Although overall demand for propane is affected by weather and other factors, we believe that residential
propane consumption is not materially affected by general economic conditions because most residential
customers consider home space heating to be an essential purchase. In addition, we own nearly 90% of the
propane tanks located at our customers’ homes. In many states, fire safety regulations restrict the refilling of a
leased tank solely to the propane supplier that owns the tank. These regulations, which require customers to
switch propane tanks when they switch suppliers, help enhance the stability of our customer base because of the
inconvenience and costs involved with switching tanks and suppliers.
Regionally Branded Operating Structure
We believe that our success in maintaining customer stability and our low cost operating structure at our
customer service centers results from our decentralized operation under established, locally recognized trade
names. We attempt to capitalize on the reputation of the companies we acquire by retaining their local brand
names and employees, thereby preserving the goodwill of the acquired business and fostering employee loyalty
and customer retention. We expect our local branch management to continue to manage the marketing programs,
new business development, customer service and customer billing and collections. We believe that our employee
incentive programs encourage efficiency and allow us to control costs at the corporate and field levels.
Operations in Attractive Propane Markets
A majority of our propane operations are concentrated in attractive propane market areas, where natural gas
distribution is not cost-effective, margins are relatively stable and tank control is relatively high. We intend to
pursue acquisitions in similar attractive markets.
8
Comprehensive Propane Logistics and Distribution Business
One of our distinguishing strengths is our propane procurement and distribution expertise and capabilities. For
the fiscal year ended September 30, 2009, we delivered 380.6 million gallons of propane on a wholesale basis to
our various customers. These operations are significantly larger on a relative basis than the wholesale operations
of most publicly-traded propane businesses. We also provide transportation services to these distributors through
our fleet of transport vehicles, and price risk management services to our customers through a variety of financial
and other instruments. The presence of our trucks serving our wholesale customers allows us to take advantage of
various pricing and distribution inefficiencies that exist in the market from time to time. We believe our
wholesale business enables us to obtain valuable market intelligence and awareness of potential acquisition
opportunities. Because we sell on a wholesale basis to many residential and commercial retailers, we have an
ongoing relationship with a large number of businesses that may be attractive acquisition opportunities for us.
We believe that we will have an adequate supply of propane to support our growing retail operations at prices
that are generally available only to large wholesale purchasers. This purchasing scale and resulting expertise also
helps us avoid shortages during periods of tight supply to an extent not generally available to other retail propane
distributors.
Midstream Business Strengths
Strategically Located Assets
Our assets are situated close to or within demand based market areas, which positions us well to leverage the
services we offer to our customers relative to our competitors. We own and operate natural gas storage operations
approximately 200 miles northwest of New York City. These assets are among the closest natural gas storage
facilities to the New York City market and have the capability of delivering gas to this market as well as other
Northeast and Mid-Atlantic market centers. We also own and operate US Salt, a salt production company located
in Schuyler County, New York, between our Stagecoach and Steuben natural gas storage facilities, which we
believe may add additional gas storage capacity to our operations in the Northeast. We also own and operate an
NGL operation near Bakersfield, California, strategically situated between the major refining centers of Los
Angeles and San Francisco. We believe there are opportunities to further leverage our geographic location,
expand our current asset base and to enhance the platform of services we offer to our customers that will further
enhance the value and profitability of these assets.
Ability to Leverage Industry Relationships
Our management team has extensive industry relationships and they have been successful in leveraging these
relationships with both new and existing customers of our midstream operations into profitable opportunities to
further grow our operations.
Stable Cash Flows
Our midstream operations consist predominantly of fee-based services that generate stable cash flows. Our
Stagecoach operations are 100% fee-based with a weighted average contract maturity which extends to
September 2014. Steuben and Bath operations are also 100% fee-based with contracted maturities extending out
several years. These contracts are with investment-grade rated customers such as large east coast utilities and
major gas marketing firms. In addition, our West Coast NGL operations include fee-based services and have
relatively little exposure to fluctuations in commodity prices. We believe that this further adds to our stable cash
flow and enhances our access to the capital markets.
Operations
Our operations reflect our two reportable segments: propane operations and midstream operations.
9
Propane Operations
Retail Propane
Customer Service Centers
At October 30, 2009, we distributed propane to approximately 700,000 retail customers from 312 customer
service centers in 28 states. We market propane primarily in rural areas, but also have a significant number of
customers in suburban areas where energy alternatives to propane such as natural gas are generally not available.
We market our propane primarily in the eastern half of the United States through our customer service centers
using multiple regional brand names. The following table shows our customer service centers by state:
State
Alabama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Connecticut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Georgia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maryland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Massachusetts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mississippi
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
New Hampshire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
New Jersey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
North Carolina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rhode Island . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
South Carolina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tennessee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vermont
Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of
Customer
Service
Centers
40
2
4
20
4
4
25
2
4
6
6
31
29
3
3
11
11
26
3
14
1
3
9
27
10
4
2
8
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
312
From our customer service centers, we also sell, install and service equipment related to our propane distribution
business, including heating and cooking appliances. Typical customer service centers consist of an office and
service facilities, with one or more 12,000 to 30,000 gallon bulk storage tanks. Some of our customer service
centers also have an appliance showroom. We have several satellite facilities that typically contain only large
capacity storage tanks.
10
Customer Deliveries
Retail deliveries of propane are usually made to customers by means of our fleet of bobtail and rack trucks.
Propane is pumped from the bobtail truck, which generally holds 2,500 to 3,000 gallons, into a stationary storage
tank at the customer’s premises. The capacity of these tanks range from 100 gallons to 1,200 gallons, with a
typical tank having a capacity of 100 to 300 gallons in milder climates and 500 to 1,000 gallons in colder
climates. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of
five to thirty-five gallons. These cylinders typically are picked up by us and replenished at our distribution
locations, then returned to the retail customer. To a limited extent, we also deliver propane to certain customers
in larger trucks known as transports, which have an average capacity of 10,000 gallons. These customers include
industrial customers, large-scale heating accounts and large agricultural accounts.
During the fiscal year ended September 30, 2009, we delivered approximately 45% of our propane volume to
retail customers and 55% to wholesale customers. Our retail volume sold to residential, industrial and
commercial and agricultural customers were as follows:
•
•
•
70% to residential customers;
23% to industrial and commercial customers; and
7% to agricultural customers.
No single retail customer accounted for more than 1% of our revenue during the fiscal year ended September 30,
2009.
Approximately half of our residential customers receive their propane supply under an automatic delivery
program. Under the automatic delivery program, we deliver propane to our heating customers approximately six
times during the year. We determine the amount of propane delivered based on weather conditions and historical
consumption patterns. Our automatic delivery program eliminates the customer’s need to make an affirmative
purchase decision, promotes customer retention by ensuring an uninterrupted supply and enables us to efficiently
route deliveries on a regular basis. We promote this program by offering level payment billing, discounts, fixed
price options and price caps. In addition, we generally provide emergency service 24 hours a day, seven days a
week, 52 weeks a year.
Seasonality
The retail propane business is seasonal with weather conditions significantly affecting demand for propane. We
believe that the geographic diversity of our areas of operations helps to minimize our exposure to regional
weather. Although overall demand for propane is affected by climate, changes in price and other factors, we
believe our residential and commercial business to be relatively stable due to the following characteristics:
•
•
•
•
residential and commercial demand for propane has not been significantly affected by general economic
conditions due to the largely non-discretionary nature of most propane purchases by our customers;
loss of customers to competing energy sources has been low;
the tendency of our customers to remain with us due to the product being delivered pursuant to a regular
delivery schedule and to our ownership of approximately 90% of the storage tanks utilized by our
customers; and
our ability to offset customer losses through a combination of acquisitions and to a lesser extent, sales to
new customers in existing markets.
Since home heating usage is the most sensitive to temperature, residential customers account for the greatest
usage variation due to weather. Variations in the weather in one or more regions in which we operate can
significantly affect the total volumes of propane we sell and the margins we realize and, consequently, our results
of operations. We believe that sales to the commercial and industrial markets, while affected by economic
patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.
11
Transportation Assets and Truck Maintenance
Our transportation assets are operated by L&L Transportation, LLC, a wholly-owned subsidiary of Inergy
Propane. The transportation of propane requires specialized equipment. Propane trucks carry specialized steel
tanks that maintain the propane in a liquefied state. As of September 30, 2009, we owned a fleet of 191 tractors,
571 transports, 1,330 bobtail and rack trucks and 884 other service vehicles. In addition to supporting our retail
and wholesale propane operations, our fleet is also used to deliver butane and ammonia for third parties and to
distribute natural gas for various processors and refiners.
We own truck maintenance facilities located in Indiana, Ohio and Mississippi. We also have a trucking operation
located in California as part of our NGL business. We believe that our ability to maintain the trucks we use in our
propane operations significantly reduces the costs we would otherwise incur with third parties in maintaining our
fleet of trucks.
Pricing Policy
Our pricing policy is an essential element in our successful marketing of propane. We base our pricing decisions
on, among other things, prevailing supply costs, local market conditions and local management input. We rely on
our regional management to set prices based on these factors. Our local managers are advised regularly of any
changes in the posted prices of our propane suppliers. We believe our propane pricing methods allow us to
respond to changes in supply costs in a manner that protects our customer base and gross margins. In some cases,
however, our ability to respond quickly to cost increases could cause our retail prices to rise more rapidly than
those of our competitors, possibly resulting in a loss of customers.
Billing and Collection Procedures
We retain our customer billing and account collection responsibilities at the local level. We believe that this
decentralized approach is beneficial for a number of reasons:
•
•
•
•
customers are billed on a timely basis;
customers are more likely to pay a local business;
cash payments are received faster; and
local personnel have current account information available to them at all times in order to answer
customer inquiries.
Trademarks and Trade Names
We use a variety of trademarks and trade names which we own, including “Inergy” and “Inergy Services.” We
believe that our strategy of retaining the names of the companies we acquire has maintained the local
identification of such companies and has been important to the continued success of the acquired businesses. We
regard our trademarks, trade names and other proprietary rights as valuable assets and believe that they have
significant value in the marketing of our products.
Wholesale Supply, Marketing and Distribution Operations
We currently provide wholesale supply, marketing and distribution services to independent dealers, multi-state
marketers, petrochemical companies, refinery and gas processors and a number of other NGL marketing and
distribution companies, primarily in the Midwest and Southeast. While our wholesale supply, marketing and
distribution operations accounted for 25% of total revenue, this business represented 4% of our gross profit
during the fiscal year ended September 30, 2009.
12
Marketing and Distribution
Because of the size of our wholesale operations one of our distinguishing strengths is our procurement and
distribution expertise and capabilities. This is partly the result of the unique background of our management
team, which has significant experience in the procurement aspects of the propane business. We also offer
transportation services to these distributors through our fleet of transport trucks and price risk management
services to our customers through a variety of financial and other instruments. Our wholesale supply, marketing
and distribution business provides us with an additional income stream as well as extensive market intelligence
and acquisition opportunities. In addition, these operations provide us with more secure supplies and better
pricing for our customer service centers. Moreover, the presence of our trucks across the Midwest and Southeast
allows us to take advantage of various pricing and distribution inefficiencies that exist in the market from time to
time.
Supply
We obtain a substantial majority of our propane from domestic suppliers, with our remaining propane
requirements provided by Canadian suppliers. During the fiscal year ended September 30, 2009, a majority of our
sales volume was purchased pursuant to contracts that have a term of one year or less; the balance of our sales
volume was purchased on the spot market. The percentage of our contract purchases varies from year to year.
Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the
current prices established at major storage points, and some contracts include a pricing formula that typically is
based on such market prices. Some of these agreements provide maximum and minimum seasonal purchase
guidelines.
Two suppliers, BP Amoco Corp. (12%) and Sunoco, Inc. (11%), accounted for 23% of propane purchases during
the past fiscal year. We believe that contracts with these suppliers will enable us to purchase most of our supply
needs at market prices and ensure adequate supply. No other single supplier accounted for more than 10% of
propane purchases in the current year.
Propane generally is transported from refineries, pipeline terminals, storage facilities and marine terminals to our
approximate 650 bulk storage tank facilities. We accomplish this by using our transports and contracting with
common carriers, owner-operators and railroad tank cars. Our customer service centers and satellite locations
typically have one or more 12,000 to 30,000 gallon storage tanks, which are generally adequate to meet customer
usage requirements for seven days during normal winter demand. Additionally, we lease underground storage
facilities from third parties under annual lease agreements.
We engage in risk management activities in order to reduce the effect of price volatility on our product costs and
to help ensure the availability of propane during periods of short supply. We are currently a party to propane
forward and option contracts with various third parties to purchase and sell propane at fixed prices in the future.
We monitor these activities through enforcement of our risk management policy.
Midstream Operations
Natural Gas Storage Operations
Stagecoach was acquired on August 9, 2005, and is a high performance, multi-cycle natural gas storage facility
with 26.25 bcf of working storage capacity of natural gas, maximum withdrawal capability of 500 MMcf/day and
maximum injection capability of 250 MMcf/day. Located approximately 150 miles northwest of New York City,
the Stagecoach facility is currently connected to Tennessee Gas Pipeline Company’s 300 Line and the
Millennium Pipeline and is a significant participant in the northeast United States natural gas distribution system.
The Stagecoach facility is 100% contracted with predominantly investment-grade rated customers such as large
east coast utility companies and major gas marketing firms.
13
ASC was acquired in October 2007 and is the majority owner and operator of Steuben, which owns a natural gas
storage facility located in Steuben County, New York, with 6.2 bcf of working gas capacity, maximum
withdrawal capability of 60 MMcf/day and maximum injection capability of 30 MMcf/day. The facility was
developed and placed in commercial service in 1991. The storage capacity at Steuben is fully contracted under
long-term agreements with investment-grade rated customers. Located approximately 30 miles northwest of
Corning, New York, the Steuben facility is currently connected to Dominion Gas Transmission’s Woodhull line
and is a critical component of the northeast United States natural gas market.
Thomas Corners, a 7 bcf (working) natural gas storage facility located in Steuben County, New York, was placed
into service in November 2009. Beginning in April 2010, the storage capacity at Thomas Corners will be fully
contracted under long-term agreements with investment-grade rated customers. We expect Thomas Corners to
generate revenue from interruptible storage contracts during the period November 2009 through March 2010.
This facility has maximum withdrawal and injection capabilities of 140 MMcf/day and 70 MMcf/day,
respectively. Thomas Corners is connected with the Tennessee Gas Pipeline Company’s Line 400 and Columbia
Gas Transmission’s A-5 line (which was acquired by the Millennium Pipeline and as such the Thomas Corners
facility is also connected with the Millennium Pipeline).
LPG Storage Operations
Our Bath LPG Storage Facility, acquired in October 2006, is a 1.7 million barrel salt cavern storage facility
located near Bath, New York, approximately 210 miles northwest of New York City and approximately 60 miles
from our Stagecoach facility. The facility is supported by both rail and truck terminals capable of loading and
unloading 20-23 rail cars per day and 17 truck transports per day. The facility is currently fully contracted under
long-term agreements for butane and propane storage.
NGL Operations
Our NGL business, acquired in 2003, is located near Bakersfield, California. The facility includes a 25.0 MMcf/
day natural gas processing plant, a 12,000 bpd NGL fractionation plant, an 8,000 bpd butane isomerization plant,
NGL rail and truck terminals, a 24.0 million gallon NGL storage facility and NGL transportation/marketing
operations.
Salt Operations
Our US Salt facility, acquired in August 2008, is located in Schuyler County, New York, and produces salt using
solution mining and mechanical evaporation. The facility is strategically located between our Stagecoach and
Steuben facilities. The facility produces and sells over 300,000 tons of salt each year. The US Salt facility has
existing cavern space that we are currently developing into a 5 million barrel LPG storage facility that we expect
to place into service in the spring of 2010. There is also existing cavern space that we intend to convert to
approximately 10 bcf of natural gas storage. With each new brine well that we drill we create additional potential
storage capacity.
For more information on our reportable business segments, see Note 13 to our consolidated financial statements.
Employees
As of October 30, 2009, we had 2,822 full-time employees and 88 part-time employees. Of the 2,910 employees,
125 were general and administrative and 2,785 were operational. Of the operational employees, 230 were
members of labor unions. We believe that our relationship with our employees is satisfactory.
14
Government Regulation
National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures
governing the safe handling of propane, or comparable regulations, have been adopted as the law in substantially
all of the states in which we operate. In some states these laws are administered by state agencies, and in others
they are administered on a county or municipal level. Regarding the transportation of propane, ammonia and
butane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These
regulations cover the transportation of hazardous materials and are administered by the United States Department
of Transportation. We conduct ongoing training programs to help ensure that our operations are in compliance
with applicable regulations. We maintain various permits that are necessary to operate some of our facilities,
some of which may be material to our operations. We believe that the procedures currently in effect at all of our
facilities for the handling, storage and distribution of propane and the transportation of ammonia and butane are
consistent with industry standards and are in compliance in all material respects with applicable laws and
regulations.
Our midstream operations are subject to federal, state and local regulatory authorities. Specifically, the
Stagecoach, Steuben and Thomas Corners natural gas storage facilities are subject to the regulation of the Federal
Energy Regulatory Commission (“FERC”).
Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate gas transportation services in
interstate commerce, including storage services. FERC’s authority to regulate those services includes the rates
charged for the services, terms and conditions of service, 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, the initiation and discontinuation of services, relationships with affiliated entities and
various other matters. Natural gas companies may not charge rates that, upon review by FERC, are found to be
unjust, unreasonable, or unduly discriminatory. In addition, FERC prohibits natural gas companies from unduly
preferring or unreasonably discriminating against any person with respect to pipeline transportation rates or terms
and conditions of service. The rates and terms and conditions for such services are found in the FERC-approved
tariff of Central New York Oil and Gas Company, LLC (“CNYOG”), the owner of the Stagecoach facility, the
FERC-approved tariff of Steuben Gas Storage Company, the owner of the Steuben facility and the FERC-
approved tariff of ASC, the owner of the Thomas Corners facility. Pursuant to the NGA, existing interstate
transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC.
Additionally, rate increases proposed by the regulated pipeline or storage provider may be challenged by protest
and such proposed increases may ultimately be rejected by FERC. CNYOG and ASC currently hold authority
from FERC to charge and collect market-based rates for services provided at the Stagecoach facility and Thomas
Corners facility, respectively. Steuben Gas Storage Company currently holds authority from FERC to charge and
collect cost of service rates at the Steuben facility. There can be no guarantee that CNYOG and ASC will be
allowed to continue to operate under such a rate structure for the remainder of the Stagecoach and Thomas
Corners facilities’ operating lives. Any successful complaint or protest against rates charged for CNYOG’s or
ASC’s storage and related services, or CNYOG’s or ASC’s loss of market-based rate authority, could have an
adverse impact on our revenues.
In addition, CNYOG’s or ASC’s market-based rate authority would be subject to further review if we acquire
transportation facilities or additional storage capacity, if we or one of our affiliates provides storage or
transportation services in the same market area or acquires an interest in another storage field that can link our
facilities to the market area or if we or one of our affiliates acquire an interest in or is acquired by an interstate
pipeline.
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, transportation and storage facilities. Any successful complaint or protest against such
rates or loss of market-based rate authority could have an adverse impact on our revenues associated with
providing storage services.
15
In August, 2005, Congress enacted legislation that, among other matters, amends the NGA to make it unlawful
for “any entity” to use any deceptive or manipulative device or contrivance in connection with the purchase or
sale of natural gas or the purchase or sale of transportation services, including storage services such as those
provided by the Stagecoach facility, subject to FERC regulation, in contravention of rules prescribed by FERC.
On January 20, 2006, FERC issued rules implementing this provision. The rules make it unlawful for any entity,
in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale
of FERC-regulated transportation services, directly or indirectly, to use or employ any device, scheme or artifice
to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make
the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon
any entity. The new legislation also amends the NGA to give FERC authority to impose civil penalties for
violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to
activities that relate only to intrastate or other non-jurisdictional sales, gas processing, or gathering, but does
apply to activities of interstate gas pipelines and storage providers, as well as otherwise non-jurisdictional
entities, such as gas processors, to the extent the activities are conducted “in connection with” gas sales,
purchases or transportation subject to FERC jurisdiction. It therefore reflects an expansion of FERC’s NGA
enforcement authority.
Certain aspects of our midstream operations are also subject to the Pipeline Safety Act of 2002, as amended by
the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which provides guidelines in the area of
testing, education, training and communication. In addition to pipeline integrity tests, pipeline and storage
companies are required to implement a qualification program to make certain that employees are properly
trained. The United States Department of Transportation has approved our qualification program. We believe that
we are in substantial compliance with these requirements and have integrated appropriate aspects of the law into
our Operator Qualification Program, which is in place and functioning.
Additionally, we are subject to stringent federal, state and local environmental, health and safety laws and
environmental regulations governing our operations. These laws and regulations impose limitations on the
discharge and emission of pollutants and establish standards for the handling of solid and hazardous wastes.
Applicable laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental
Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health
Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state or
local statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liability without regard to
fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to
the release or threatened release of a hazardous substance into the environment. While propane is not a hazardous
substance within the meaning of CERCLA, other chemicals used in our operations may be classified as
hazardous substances. Failure to comply with these laws and regulations may result in the assessment of
administrative, civil or criminal penalties, the imposition of remedial liabilities and the issuance of injunctions
restricting or prohibiting our activities. 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 expenditure thereunder.
For acquisitions that involve the purchase of real estate, we conduct due diligence investigations to assess
whether any material or waste has been sold from, or stored on, or released or spilled from any of that real estate
prior to its purchase. This due diligence includes questioning the seller, obtaining representations and warranties
concerning the seller’s compliance with environmental laws and performing site assessments. During these due
diligence investigations, our employees, and, in certain cases, independent environmental consulting firms,
review historical records and databases and conduct physical investigations of the property to look for evidence
of contamination, compliance violations and the existence of underground storage tanks.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse
gas” and including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning
of fuels such as propane and natural gas, may be contributing to warming of the Earth’s atmosphere. In response
16
to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In
addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and
trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al.
v. EPA, the U.S. Environmental Protection Agency or “EPA” may be required to regulate greenhouse gas
emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse
gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of
greenhouse gas emissions from stationary sources under certain Clean Air Act programs. Passage of climate
control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of
regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases in areas in which
we conduct business could have an adverse affect on our operations and demand for our services.
In addition, the Department of Homeland Security Appropriations Act of 2007 requires the Department of
Homeland Security or “DHS” to issue regulations establishing risk-based performance standards for the security
of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of
security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to
be attained pursuant to the act and the DHS has adopted an Appendix A to the interim rules that establish the
chemicals of concern and their respective threshold quantities that will trigger compliance with the interim rules.
Future developments, such as stricter environmental, health or safety laws and regulations, or more stringent
enforcement of existing requirements could affect our operations. We do not anticipate that our compliance with
or liabilities under environmental, health and safety laws and regulations, including CERCLA, will require any
material increase in our capital expenditures or otherwise have a material adverse effect on us. To the extent that
any environmental liabilities, or environmental, health or safety laws, or regulations are made more stringent,
there can be no assurance that our results of operations will not be materially and adversely affected.
Item 1A. Risk Factors
Risks Inherent in Our Business
Future acquisitions and completion of expansion projects will require significant amounts of debt and equity
financing which may not be available to us on acceptable terms, or at all.
We plan to fund our acquisitions and expansion capital expenditures, including any future expansions we may
undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit
facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms or in
the proportions that we expect, or at all, and we may be unable refinance our revolving credit facility when it
expires. In addition, we may be unable to obtain adequate funding under our current revolving credit facility
because our lending counterparties may be unable to meet their funding obligations.
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt
and equity capital markets have been distressed. These issues, along with significant write-offs in the financial
services sector, the re-pricing of credit risk and the current weak economic conditions may make it difficult to
obtain funding.
The cost of raising money in the debt and equity capital markets has increased while the availability of funds
from those markets generally has diminished. Also, as a result of concerns about the stability of financial markets
generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets
generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter
lending standards, refused to refinance existing debt at maturity or on terms similar to our current debt and
reduced and, in some cases, ceased to provide funding to borrowers.
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A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than
our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed
above could negatively impact our credit ratings or our ability to remain in compliance with the financial
covenants under our revolving credit agreement which could have a material adverse effect on our financial
condition, results of operations and cash flows. If we are unable to finance acquisitions or our expansion projects
as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or
to revise or cancel our expansion plans.
If we do not continue to make acquisitions on economically acceptable terms, our future financial
performance may be limited.
Due to increased competition from alternative energy sources the propane industry is not a growth industry. In
addition, as a result of long-standing customer relationships that are typical in the retail home propane industry,
the inconvenience of switching tanks and suppliers and propane’s higher cost as compared to other energy
sources, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore,
while our operating objectives include promoting internal growth, our ability to grow depends principally on
acquisitions. Our future financial performance depends on our ability to continue to make acquisitions at
attractive prices. There is no assurance that we will be able to continue to identify attractive acquisition
candidates in the future or that we will be able to acquire businesses on economically acceptable terms. In
particular, competition for acquisitions in the propane business has intensified and become more costly. We may
not be able to grow as rapidly as we expect through our acquisition of additional businesses for various reasons,
including the following:
• We will use our cash from operations primarily to service our debt and for distributions to unitholders
and reinvestment in our business. Consequently, the extent to which we are unable to use cash or access
capital to pay for additional acquisitions may limit our growth and impair our operating results. Further,
we are subject to certain debt incurrence covenants under our bank credit agreement and the indentures
that govern our senior notes that may restrict our ability to incur additional debt to finance acquisitions.
• Although we intend to use our securities as acquisition currency, some prospective sellers may not be
willing to accept our securities as consideration.
• We will use cash for capital expenditures related to expansion projects, which will reduce our cash
available to pay for additional acquisitions.
Moreover, acquisitions involve potential risks, including:
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our inability to integrate the operations of recently acquired businesses;
the diversion of management’s attention from other business concerns;
customer or key employee loss from the acquired businesses; and
a significant increase in our indebtedness.
Our growth strategy includes acquiring entities with lines of business that are distinct and separate from our
existing operations which could subject us to additional business and operating risks.
Consistent with our announced growth strategy and our acquisition of the US Salt facility and related assets, we
may acquire assets that have operations in new and distinct lines of business from our existing operations.
Integration of new business segments is a complex, costly and time-consuming process and may involve assets in
which we have limited operating experience. Failure to timely and successfully integrate acquired entities’ new
lines of business with our existing operations may have a material adverse effect on our business, financial
condition or results of operations. The difficulties of integrating new business segments with existing operations
include, among other things:
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operating distinct business segments that require different operating strategies and different managerial
expertise;
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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 our 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 our existing
business, results of operations, financial condition or prospects. Furthermore, new lines of business will subject
us to additional business and operating risks which could have a material adverse effect on our financial
condition or results of operations.
We may be unable to successfully integrate our recent acquisitions.
One of our primary business strategies is to grow through acquisitions. There is no assurance that we will
successfully integrate acquisitions into our operations, or that we will achieve the desired profitability from our
acquisitions. Failure to successfully integrate these substantial acquisitions could adversely affect our operations.
The difficulties of combining the acquired operations include, among other things:
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operating a significantly larger combined organization and integrating additional retail and wholesale
distribution operations to our existing supply, marketing and distribution operations;
coordinating geographically disparate organizations, systems and facilities;
integrating personnel from diverse business backgrounds and organizational cultures;
consolidating corporate, technological and administrative functions;
integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate
governance matters;
the diversion of management’s attention from other business concerns;
customer or key employee loss from the acquired businesses;
a significant increase in our indebtedness; and
potential environmental or regulatory liabilities and title problems.
In addition, we 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.
Our indebtedness may limit our ability to borrow additional funds, make distributions to our unitholders, or
capitalize on acquisition or other business opportunities, in addition to impairing our ability to fulfill our debt
obligation under our senior notes.
As of September 30, 2009, we had $1.1 billion of total outstanding indebtedness. Our leverage, various
limitations in our credit facility, other restrictions governing our indebtedness and the indentures governing our
senior notes may reduce our ability to incur additional indebtedness, to engage in some transactions and to
capitalize on acquisition or other business opportunities.
Our indebtedness and other financial obligations could have important consequences. For example, they could:
• make it more difficult for us to make distributions to our unitholders;
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impair our ability to obtain additional financing in the future for working capital, capital expenditures,
acquisitions, general partnership purposes or other purposes;
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result in higher interest expense in the event of increases in interest rates since some of our debt is, and
will continue to be, at variable rates of interest;
have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our
debt agreements and an event of default occurs as a result of that failure that is not cured or waived;
require us to dedicate a substantial portion of our cash flow to payments of our indebtedness and other
financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital
expenditures and other general partnership requirements;
limit our flexibility in planning for, or reacting to, changes in our business and the propane industry; and
place us at a competitive disadvantage compared to our competitors that have proportionately less debt.
If we are unable to meet our debt service obligations and other financial obligations, we could be forced to
restructure or refinance our indebtedness and other financial transactions, seek additional equity capital or sell
our assets. We may then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at
all.
A change of control could result in us facing substantial repayment obligations under our credit facility and
our senior notes.
Our bank credit agreement and the indentures governing our senior notes contain provisions relating to change of
control of our managing general partner, our partnership and our operating company. 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.
Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.
The indentures governing our outstanding senior notes and agreements governing our revolving credit facilities
and other future indebtedness contain or may contain various covenants limiting our ability and the ability of our
specified subsidiaries to, among other things:
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pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated
debt;
• make investments;
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incur or guarantee additional indebtedness or issue preferred securities;
create or incur certain liens;
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates;
create unrestricted subsidiaries; and
create non-guarantor subsidiaries.
These restrictions could limit our ability and the ability of our subsidiaries to obtain future financings, make
needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct
operations or otherwise take advantage of business opportunities that may arise. Our bank credit agreement
contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions. We
may be unable to meet those ratios and conditions. Any future breach of these covenants and our failure to meet
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any of those ratios and conditions could result in a default under the terms of our bank credit agreement, which
could result in the acceleration of our debt and other financial obligations. If we were unable to repay these
amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the
collateral.
We are subject to operating and litigation risks that could adversely affect our operating results to the extent
not covered by insurance.
Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and
providing customers with combustible products such as propane and natural gas. As a result, we have been, and
likely will 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, the occurrence of a serious
accident, whether or not we are involved, may have an adverse effect on the public’s desire to use our products.
Our operations are subject to compliance with environmental laws and regulations that can adversely affect
our results of operations and financial condition.
Our operations are subject to stringent environmental laws and regulations of federal, state and local authorities.
Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to
conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and
restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and
wastes. Failure to comply with such environmental laws and regulations can result in the assessment of
substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the
issuance of injunctions restricting or prohibiting our activities. Certain environmental laws impose strict, joint
and several liability for costs required to clean up and restore sites where hazardous substances have been
disposed or otherwise released. In the course of our operations, 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 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. 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.
Cost reimbursements due our managing general partner may be substantial and will reduce the cash available
for principal and interest on our outstanding indebtedness.
We reimburse our managing general partner and its affiliates, including officers and directors of our managing
general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect
our ability to make payments of principal and interest on our outstanding indebtedness. Our managing general
partner has sole discretion to determine the amount of these expenses. In addition, our managing general partner
and its affiliates provide us with services for which we are charged reasonable fees as determined by our
managing general partner in its sole discretion.
Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act
could cause us to incur additional expenditures of time and financial resources.
We have completed the process of documenting and testing our internal control procedures in order to satisfy the
requirements of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the
effectiveness of our internal controls over financial reporting and a report by our independent registered public
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accounting firm on our controls over financial reporting. If, in the future, we fail to maintain the adequacy of our
internal controls, as such standards are modified, supplemented or amended from time to time, we may not be
able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial
reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective
internal control environment could cause us to incur substantial expenditures of management time and financial
resources to identify and correct any such failure.
Climate change legislation, regulatory initiatives and litigation may adversely affect our operations.
On April 17, 2009, the EPA issued a notice of its proposed finding and determination that emissions of carbon
dioxide, methane and other “greenhouse gases” presented an endangerment to human health and the environment
because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere and
other climatic changes. Once finalized, EPA’s finding and determination would allow the agency to begin
regulating emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late
September 2009, EPA proposed two sets of regulations in anticipation of finalizing its findings and
determination, one rule to reduce emissions of greenhouse gases from motor vehicles and the other to control
emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be
adopted in March 2010, it may take EPA several years to adopt and impose regulations limiting emissions of
greenhouse gases from stationary sources. Any limitation on emissions of greenhouse gases from our equipment
and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our
operations.
Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act
of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S.
emissions of “greenhouse gases” including carbon dioxide and methane that may contribute to warming of the
Earth’s atmosphere and other climatic changes. ACESA would require a 17% reduction in greenhouse gas
emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this
legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to
major sources of greenhouse gas emissions, including producers of NGLs (i.e., natural gas fractionators), local
distribution companies and certain industrial facilities, so that such sources could continue to emit greenhouse
gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The
U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and
President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission
allowance system. Although it is not possible at this time to predict when the Senate may act on climate change
legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or
implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur
increased operating costs and could adversely affect demand for the natural gas and NGL products and services
we provide.
Risks Related to Our Propane Operations
Since weather conditions may adversely affect the demand for propane, our financial condition and results of
operations are vulnerable to, and will be adversely affected by, warm winters.
Weather conditions have a significant impact on the demand for propane because many of our customers depend
on propane principally for heating purposes. As a result, warm weather conditions will adversely impact our
operating results and financial condition. Actual weather conditions can substantially change from one year to the
next. Furthermore, warmer than normal temperatures in one or more regions in which we operate can
significantly decrease the total volume of propane we sell. Consequently, our operating results may vary
significantly due to actual changes in temperature. During seven of the last ten fiscal years temperatures were
significantly warmer than normal in our areas of operation (based on the 30-year average consisting of years
1976 through 2005 published by the National Oceanic and Atmospheric Administration). We believe that our
results of operations during these periods were adversely affected as a result of this warm weather.
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Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our
profit margins.
The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices
over supply costs. As a result, our profitability is sensitive to changes in wholesale prices of propane caused by
changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of
propane, we may not be able to pass on these increases to our customers through retail or wholesale prices.
Propane is a commodity and the price we pay for it can fluctuate significantly in response to changes in supply or
other market conditions. We have no control over supply or market conditions. In addition, the timing of cost
pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our
gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail
customers to conserve or convert to alternative energy sources.
The highly competitive nature of the retail propane business could cause us to lose customers or affect our
ability to acquire new customers, thereby reducing our revenues.
We have competitors and potential competitors who are larger and have substantially greater financial resources
than we do. Also, because of relatively low barriers to entry into the retail propane business, numerous small
retail propane distributors, as well as companies not engaged in retail propane distribution, may enter our markets
and compete with us. Most of our propane retail branch locations compete with several marketers or distributors.
The principal factors influencing competition with other retail marketers are:
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price;
reliability and quality of service;
responsiveness to customer needs;
safety concerns;
long-standing customer relationships;
the inconvenience of switching tanks and suppliers; and
the lack of growth in the industry.
We can make no assurances that we will be able to compete successfully on the basis of these factors. If a
competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce
our revenues.
If we are not able to purchase propane from our principal suppliers, our results of operations would be
adversely affected.
Most of our total volume purchases are made under supply contracts that have a term of one year, are subject to
annual renewal, and provide various pricing formulas. Two of our suppliers, BP Amoco Corp.
(12%) and Sunoco, Inc. (11%), accounted for 23% of propane purchases during the fiscal year ended
September 30, 2009. In the event that we are unable to purchase propane from our significant suppliers, our
failure to obtain alternate sources of supply at competitive prices and on a timely basis may hurt our ability to
satisfy customer demand, reduce our revenues and adversely affect our results of operations.
Competition from other energy sources may cause us to lose customers, thereby reducing our revenues.
Competition from other energy sources, including natural gas and electricity, has been increasing as a result of
reduced regulation of many utilities, including natural gas and electricity. Propane is generally not competitive
with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source
of energy than propane. The gradual expansion of natural gas distribution systems and availability of natural gas
in many areas that previously depended upon propane could cause us to lose customers, thereby reducing our
revenues.
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Our business would be adversely affected if service at our principal storage facilities or on the common carrier
pipelines we use is interrupted.
Historically, a substantial portion of the propane purchased to support our operations has originated at Conway,
Kansas, Hattiesburg, Mississippi and Mont Belvieu, Texas and has been shipped to us through major common
carrier pipelines. Any significant interruption in the service at these storage facilities or on the common carrier
pipelines we use would adversely affect our ability to obtain propane.
If we are not able to sell propane that we have purchased through wholesale supply agreements to either our
own retail propane customers or to other retailers and wholesalers, the results of our operations would be
adversely affected.
We currently are party to propane supply contracts and expect to 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 in our own propane distribution business, to other 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. We are also a party to fixed price sale contracts with certain customers that are backed-up
by propane supply contracts. If a significant number of our customers default under these fixed price contracts
the results of our operations would be adversely affected.
Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating
results.
Increased conservation and technological advances, including installation of improved insulation and the
development of more efficient furnaces and other heating devices, have adversely affected the demand for
propane by retail customers. Future conservation measures or technological advances in heating, conservation,
energy generation or other devices might reduce demand for propane and adversely affect our operating results.
Due to our limited asset diversification, adverse developments in our propane business could adversely affect
our operating results and reduce our ability to make distributions to our unitholders.
We rely substantially on the revenues generated from our propane business. Due to our limited asset
diversification, an adverse development in this business would have a significantly greater impact on our
financial condition and results of operations than if we maintained more diverse assets.
Risks Related to Our Midstream Operations
Federal, state or local regulatory measures could adversely affect our business.
Our operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas storage
facilities are subject to the regulation of the Federal Energy Regulatory Commission, or FERC.
Under the Natural Gas Act of 1938 (“NGA”), FERC has authority to regulate our natural gas facilities that
provide natural gas transportation services in interstate commerce, including storage services. FERC’s authority
to regulate those services includes the rates charged for the services, terms and conditions of service, 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, the initiation and discontinuation of services,
relationships with affiliated entities 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. In addition, FERC
prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with
respect to pipeline transportation rates or terms and conditions of service. The rates and terms and conditions for
interstate services provided by the Steuben facility are found in the FERC-approved tariff of Steuben Gas Storage
Company. The rates and terms and conditions for interstate services provided by Stagecoach are found in the
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FERC-approved tariff of Central New York Oil and Gas Company, LLC (“CNYOG”), our subsidiary and owner
of the Stagecoach facility. The rates and terms and conditions for interstate services provided by the Thomas
Corners facility are found in the FERC-approved tariff of Arlington Storage Company, LLC (“ASC”), our
subsidiary and owner of the Thomas Corners facility.
Pursuant to the NGA, existing interstate transportation and storage rates may be challenged by complaint and are
subject to prospective change by FERC. Additionally, rate increases proposed by the regulated pipeline or
storage provider may be challenged by protest and such increases may ultimately be rejected by FERC. CNYOG
and ASC currently hold authority from FERC to charge and collect market-based rates for services provided at
the Stagecoach facility and the Thomas Corners facility, respectively. There can be no guarantee that CNYOG
and ASC will be allowed to continue to operate under such a rate structure for the remainder of the Stagecoach
and Thomas Corners facilities’ operating lives. Any successful complaint or protest against rates charged for
CNYOG’s and ASC’s storage and related services, or CNYOG’s or ASC’s loss of market-based rate authority,
could have an adverse impact on our revenues.
In addition, CNYOG or ASC’s market-based rate authority would be subject to further review if we acquire
transportation facilities or additional storage capacity, if we or one of our affiliates provides storage or
transportation services in the same market area or acquires an interest in another storage field that can link our
facilities to the market area or if we or one of our affiliates acquire an interest in or is acquired by an interstate
pipeline.
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, transportation and storage facilities. Any successful complaint or protest against our rates
or loss of our market-based rate authority could have an adverse impact on our revenues associated with
providing storage services. Failure to comply with applicable regulations under the NGA, Natural Gas Policy Act
of 1978, 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.
Our storage business depends on neighboring pipelines to transport natural gas.
Our Stagecoach natural gas storage business depends on Tennessee Gas Pipeline Company’s 300-Line and the
Millennium Pipeline, currently the only pipelines to which it is interconnected, the Steuben natural gas storage
facility depends on the Dominion Transmission System and the Thomas Corners natural gas storage facility
depends on Tennessee Gas Pipeline Company’s 400-Line and the Millennium Pipeline. These pipelines are
owned by parties not affiliated with us. Any interruption of service on the pipeline or lateral connections or
adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the
ability of our customers, to transport natural gas to and from our facilities and have a corresponding material
adverse effect on our storage revenues. In addition, the rates charged by the interconnected pipelines for
transportation to and from our facilities affect the utilization and value of our storage 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 storage revenues.
We expect to derive a significant portion of our revenues from our natural gas and LPG storage operations
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.
We expect to derive a significant portion of our revenues and cash flow in connection with our natural gas and
LPG storage operations from a limited number of customers. The loss, nonpayment, nonperformance or impaired
creditworthiness of one of these customers could have a material adverse effect on our business, results of
operations and financial condition.
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We compete with other natural gas storage companies and services that can substitute for storage services.
Our principal competitors in our natural gas storage market include other storage providers including among
others Dominion Resources, Inc., NiSource Inc. and El Paso Corporation. These major pipeline natural gas
transmission companies have existing storage facilities connected to their systems that compete with certain of
our facilities. FERC has adopted policy that favors authorization of new storage projects, and there are numerous
natural gas storage options in the New York/Pennsylvania geographic market. 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.
Expanding our business by constructing new midstream assets subjects us to risks.
One of the ways we may grow our business is through the expansion of our existing assets, such as the Thomas
Corners development, the West Coast expansion project and the Watkins Glenn LPG storage facility. The
construction of additional storage facilities or new pipeline interconnects involves numerous regulatory,
environmental, political and legal uncertainties beyond our control and may require the expenditure of significant
amounts of capital. If we undertake these projects, they may not be completed on schedule or at all or at the
budgeted cost. 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 results of operations and
financial condition.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues
and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current
revenues and cash flows depends on a number of factors beyond our control, including competition from other
pipelines and storage providers, and the price of, and demand for, natural gas in the markets we serve. The
inability to renew or replace our current contracts as they expire and to respond appropriately to changing market
conditions could have a negative effect on our profitability.
The fees charged by us to third parties under transmission, transportation and storage agreements may not
escalate sufficiently to cover increases in costs and the agreements may not be renewed or 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. Furthermore, third parties may not renew their contracts with us. Additionally, 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 either natural gas are 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, if third parties do not renew or extend
their contracts with us or if any third party suspends or terminates its contracts with us, our financial results
would be negatively impacted.
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Our business would be adversely affected if operations at any of our facilities were interrupted.
Our operations are dependent upon the infrastructure that we have developed, including, storage facilities and
various means of transportation. Any significant interruption at these facilities or pipelines or our customers’
inability to transmit natural gas to or from these facilities or pipelines for any reason would adversely affect our
results of operations.
Risks Inherent in an Investment in Us
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 our managing general partner or its board of directors and will have no right to elect our
managing general partner or its board of directors on an annual or other continuing basis. The board of directors
of our managing general partner is chosen by the sole member of our managing general partner, Inergy Holdings,
L.P. Although our managing 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 managing general partner also have a fiduciary
duty to manage our managing general partner in a manner beneficial to its member, Inergy Holdings, L.P.
If unitholders are dissatisfied with the performance of our managing general partner, they will have little ability
to remove our managing general partner. Our managing 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.
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 managing general partner may be transferred to a third party without unitholder consent.
Our managing 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 managing general partner, Inergy Holdings, L.P., from
transferring its ownership interest in our managing general partner to a third party. The new owner of our managing
general partner would then be in a position to replace the board of directors and officers of our managing general
partner with its own choices and to control the decisions taken by our board of directors and officers.
Cost reimbursements due our managing general partner may be substantial and reduce our ability to pay the
minimum quarterly distribution.
Before making any distributions on our units, we will reimburse our managing general partner for all expenses it
has incurred on our behalf. In addition, our general partners and their affiliates may provide us with services for
which we will be charged reasonable fees as determined by our managing general partner. The reimbursement of
these expenses and the payment of these fees could adversely affect our ability to make distributions to you. Our
managing 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.
27
Our general partners have conflicts of interest and limited fiduciary responsibilities, which may permit our
general partners to favor their own interests to the detriment of unitholders.
Inergy Holdings, L.P. and its affiliates directly and indirectly own an aggregate limited partner interest of 7.8%
in us, own and control our managing general partner and own and control our non-managing general partner,
which owns a 0.8% general partner interest. Inergy Holdings, L.P. also owns the incentive distribution rights
under our partnership agreement. Conflicts of interest could arise in the future as a result of relationships between
Inergy Holdings, L.P., our general partners and their affiliates, on the one hand, and the partnership or any of the
limited partners, on the other hand. As a result of these conflicts our general partners may favor their own
interests and those of their affiliates over the interests of our unitholders. The nature of these conflicts includes
the following considerations:
• Our general partners may limit their liability and reduce their fiduciary duties, while also restricting the
remedies available to unitholders for actions that might, without the limitations, constitute breaches of
fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that
might otherwise be deemed a breach of fiduciary or other duties under applicable state law.
• Our general partners are allowed to take into account the interests of parties in addition to the
partnership in resolving conflicts of interest, thereby limiting their fiduciary duties to our unitholders.
• Our managing general partner determines the amount and timing of asset purchases and sales, capital
expenditures, borrowings and reserves, each of which can affect the amount of cash that is distributed to
unitholders.
• Our managing general partner determines whether to issue additional units or other equity securities of
the partnership.
• Our managing general partner determines which costs are reimbursable by us.
• Our managing general partner controls the enforcement of obligations owed to us by it.
• Our managing general partner decides whether to retain separate counsel, accountants or others to
perform services for us.
• Our managing general partner is not restricted from causing us to pay it or its affiliates for any services
rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements
with any of these entities on our behalf.
•
In some instances our managing general partner may borrow funds in order to permit the payment of
distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
The president and chief executive officer of our managing general partner effectively controls us through his
control of the general partner of Inergy Holdings and our managing general partner.
The president and chief executive officer of both the general partner of Inergy Holdings and our managing
general partner owns an economic interest of 57.0% in the general partner of Inergy Holdings and has voting
control of the general partner of Inergy Holdings. He therefore controls the general partner of Inergy Holdings
and through it, our managing general partner and may be able to influence unitholder votes. Control over these
entities gives our president and chief executive officer substantial control over our and Inergy Holdings’ business
and operations.
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.
28
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 legislation is passed that
may preclude us from qualifying for treatment as a partnership, or if we were to become subject to a material
amount of entity level taxation for state tax purposes, 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 present federal income tax treatment of publicly
traded partnerships may be modified by administrative, legislative or judicial interpretation at any time. For
example, Congress is considering changes to the existing federal income tax laws that may affect certain publicly
traded partnerships.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our
taxable income at the corporate tax rate, which is currently a maximum rate of 35%, and would likely pay state
income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no
income, gain, loss, deduction or credit would flow through to our unitholders. Because a tax would be imposed
upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment
of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our
unitholders, likely causing a substantial reduction in the value of our common units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax
purposes or otherwise subject us to entity level taxation. In addition, because of widespread state budget deficits,
several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state
income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash
available to pay distributions would be reduced. Our partnership agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise
subjects us to entity level taxation for federal, state or local income tax purposes, then the minimum quarterly
distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.
Our unitholders may be required to pay taxes even if they do not receive cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be
different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in
some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash
distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable
income or even equal to the actual tax liability that result from their share of our taxable income.
Tax gain or loss on disposition of our common units could be more or less than expected.
A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount
realized and his adjusted tax basis in those common units. Prior distributions to a unitholder in excess of the total net
taxable income allocated to that unitholder, which decreased the tax basis in that unitholder’s common unit, will, in
effect, become taxable income to that unitholder if the common unit is sold at a price greater than that unitholder’s
tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income to that unitholder. In addition, if a unitholder
sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities, regulated investment companies and foreign 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
29
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 United States federal income tax returns and pay tax on their share of
our taxable income.
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 our partnership for federal income tax purposes if there is a sale or
exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our
termination would, among other things result in the closing of our taxable year for all unitholders and could
result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which
the termination occurs. Thus, if this occurs our unitholders will be allocated an increased amount of federal
taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to
unitholders with respect to that period. Although the amount of increase cannot be estimated because it depends
upon numerous factors including the timing of the termination, the amount could be material. Our termination
currently would not affect our classification as a partnership for federal income tax purposes, but instead, we
would be treated as a new partnership for 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.
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 foreign taxes,
state and local taxes, unincorporated business taxes and estate, inheritance or intangible 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 numerous states in the United States. Unitholders may be required to file state
and local income tax returns and pay state and local income taxes 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 United States federal, state, local and foreign tax
returns.
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.
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, our costs of any contest with the IRS will be borne indirectly by our unitholders and
our managing general partner because the costs will reduce our cash available for distribution.
We have adopted certain valuation methodologies and monthly conventions that may result in a shift of
income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders
and our general partner. The adopted methodology may be viewed as understating the value of our assets. In that
case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general
partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may
have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets
30
and a lesser portion allocated to our intangible assets. The IRS may challenge the adopted valuation methods, or
our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations
of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income
or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of
common units and could have a negative impact on the value of the common units or result in audit adjustments
to our unitholders’ tax returns without the benefit of additional deductions.
We treat each purchaser of common units as having the same tax benefits without regard to the actual
common units purchased. The IRS may challenge this treatment, which could result in a unitholder owing
more tax and may adversely affect the value of the common units.
To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain
depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. These
positions may result in an understatement of deductions and an overstatement of income to our unitholders. For
example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our
outstanding units. A subsequent holder of those units may be entitled to an amortization deduction attributable to
that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they
are traded by the initial holder, we do not allocate any subsequent holder of a unit any such amortization deduction.
This approach may understate deductions available to those unitholders who own those units and may result in those
unitholders believing that they have a higher tax basis in their units than would be the case if the IRS strictly applied
certain Treasury Regulations. This, in turn, may result in those unitholders reporting less gain or more loss on a sale
of their units than would be the case if the IRS strictly applied certain Treasury Regulations.
The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under
Section 743(b). If so, because neither we nor a unitholder can identify the units to which this issue relates once
the initial holder has traded them, the IRS may assert adjustments to all unitholders selling units within the period
under audit as if all unitholders owned such units.
A successful IRS challenge to this position or other positions we may take could adversely affect the amount of
taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder’s sale of
common units and could have a negative impact on the value of the common units or result in audit adjustments
to our unitholders’ tax returns without the benefit of additional deductions.
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. The IRS may challenge this treatment, which could change the
allocation of items of income, gain, loss and deduction among our unitholders.
Under the terms of our Partnership Agreement, 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. The use of this proration method may
not be permitted under Treasury Regulations. If the IRS were to challenge this 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.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
As of October 30, 2009, we owned 204 of our 312 retail propane customer service centers and leased the
remaining centers. For more information concerning the location of our customer service centers see “Retail
31
Propane” under Item 1. We lease our Kansas City, Missouri headquarters. We lease underground storage
facilities with an aggregate capacity of 19.4 million gallons of propane at nine locations under annual lease
agreements. In addition, we own two underground storage facilities with an aggregate capacity of 23.4 million
gallons of propane and butane. We also lease capacity in several pipelines pursuant to annual lease agreements.
Tank ownership and control at customer locations are important components to our retail propane operations and
customer retention. As of September 30, 2009, we owned the following:
•
•
•
1,250 bulk storage tanks at approximately 650 locations with typical capacities of 12,000 to 30,000
gallons;
600,000 stationary customer storage tanks with typical capacities of 100 to 1,200 gallons; and
170,000 portable propane cylinders with typical capacities of up to 35 gallons.
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 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 such as propane. 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 managing 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.
On September 26, 2008, we executed a Consent Agreement and Final Order (“CAFO”) that was filed by the
United States Environmental Protection Agency, Region 1 (New England Region), in November 2008. The
CAFO relates to violations of the Clean Water Act and the Oil Pollution Prevention regulations (i.e., the Spill
Prevention Control and Countermeasure requirements for bulk oil storage facilities). Specifically, the CAFO
relates to four facilities in New Hampshire (two of which we no longer operate). Although there were no
significant releases or actual environmental damages alleged by EPA, a standard civil penalty of $157,500 was
assessed for the various non-compliance issues at the facilities. Compliance strategies, including revised SPCC
Plans, replacement and locking of valves, installation of fencing, lighting and upgraded alarms and secondary
containment, have been developed and are being implemented. The initial compliance deadline was July 1,
2009. While some of the facilities were brought into full compliance by that date, other facilities required
additional time due to various issues ranging from the unavailability of certain uniquely qualified media-specific
contractors to difficulty negotiating with the facility owner to improve the facility, and in some situations we
made the decision to terminate operations at a specific facility. Upon receipt of our request for extension, EPA
agreed to extend the CAFO compliance schedules until December 31, 2009.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of the holders of our company’s common units during the fourth quarter of the
fiscal year ended September 30, 2009.
32
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of
Equity Securities.
Since July 31, 2001 our company’s common units representing limited partner interests have been traded on
NASDAQ’s Global Select National Market under the symbol “NRGY.” The following table sets forth the range
of high and low bid prices of the common units, as reported by NASDAQ, as well as the amount of cash
distributions declared per common unit for the periods indicated.
Quarters Ended:
Fiscal 2009:
Low
High
Cash
Distribution
Per Unit
September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$25.01
21.54
17.06
12.38
$30.99
26.34
25.23
22.70
Fiscal 2008:
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$20.00
25.62
25.39
29.69
$26.90
29.49
31.94
35.10
Fiscal 2007:
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$28.53
32.44
28.01
26.63
$38.17
38.09
32.99
30.49
$0.675
0.665
0.655
0.645
$0.635
0.625
0.615
0.605
$0.595
0.585
0.575
0.565
As of November 16, 2009, our company had issued and outstanding 59,817,087 common units, which were held
by 41,988 unitholders of record.
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 (as defined) 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 managing 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 and to our non-managing general partner 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. The full definition of available cash is set forth in our partnership agreement (as
amended), which is incorporated by reference herein as an exhibit to this report. For a discussion of restrictions
on our ability to distribute cash, please see “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”
In August 2008, we issued 809,389 common units in conjunction with the acquisition of US Salt and in October
2008, we issued 309,194 common units to Blu-Gas in a private placement as a portion of the purchase price.
33
On March 23, 2006, our shelf registration statement (File No. 333-132287) was declared effective by the
Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership
securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, we are
permitted to issue these securities from time to time for general business purposes, including debt repayment,
future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus
supplement. In June 2006 and February 2007, we issued 4,312,500 common units (which included 562,500
common units issued as result of the underwriters exercising their over-allotment provision) and 3,450,000
common units (which included 450,000 common units issued as result of the underwriters exercising their over-
allotment provision), respectively. In March 2009 we issued 4,000,000 common units and in April 2009 we
issued an additional 418,000 common units as result of the underwriters exercising their over-allotment
provision. In August 2009 we issued 3,500,000 common units and in September 2009 we issued an additional
525,000 common units as result of the underwriters exercising their over-allotment provision. The proceeds from
these issuances were utilized to pay down borrowings under our credit facility. No further partnership securities
or debt securities have been offered under the shelf registration except as described above. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Sources of Capital”
under Item 7.
On September 10, 2009, our new shelf registration statement (File No. 333-158066) was declared effective by the
Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership
securities and debt securities, or any combination thereof. No securities have been issued under this registration
statement, thus the full amount is available.
The following table sets forth in tabular format, a summary of our company’s equity compensation plan
information as of September 30, 2009:
Equity Compensation Plan Information
Plan category
Equity compensation plans approved by security holders . .
Equity compensation plans not approved by security
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
(a)
—
181,900
181,900
Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights
(b)
—
$23.63
$23.63
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
(c)
—
3,636,669
3,636,669
Item 6. Selected Financial Data.
The following table sets 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, 2009,
2008, 2007, 2006 and 2005 are derived from the audited consolidated financial statements of Inergy, L.P and
Inergy Partners, LLC. The historical consolidated financial data of Inergy, L.P. and Inergy Partners, LLC 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 taxes, plus net interest expense (inclusive of
write-off of deferred financing costs) 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 and non-cash compensation expenses. EBITDA and Adjusted
34
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 and Adjusted EBITDA provide additional information for
evaluating our financial performance without regard to our financing methods, capital structure and historical
cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information for
evaluating our ability to make the minimum quarterly distribution and are presented solely as a supplemental
measure. EBITDA and Adjusted EBITDA, as we define it, 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.
Statement of Operations Data:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of product sold (excluding depreciation and
amortization as shown below): . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expenses:
Operating and administrative . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense):
Interest expense, net
. . . . . . . . . . . . . . . . . . . . . . . . .
Write-off of deferred financing costs . . . . . . . . . . . .
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes and interest of
non-controlling partners in ASC . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s
Inergy L.P.
Years Ended September 30,
2009
2008
2007
2006
2005
(in millions, except per unit data)
$1,570.6
$1,878.9
$1,483.1
$1,390.2
$1,051.9
993.3
396.9
245.2
76.7
11.5
63.5
(53.8)
—
0.8
10.5
(0.7)
726.2
325.7
195.1
50.3
0.7
79.6
(34.2)
(7.0)
0.3
38.7
(0.1)
996.9
573.7
279.6
115.8
5.2
173.1
(69.7)
—
0.1
103.5
(0.7)
1,376.7
1,026.1
502.2
457.0
247.8
83.4
8.0
117.8
(52.0)
—
1.9
67.7
(0.7)
265.6
98.0
11.5
127.1
(60.9)
—
1.0
67.2
(0.7)
(1.4)
65.1
0.58
0.57
$
$
$
$
$
$
consolidated net income . . . . . . . . . . . . . . . . . . . . . . . .
(1.4)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 101.4
Net income (loss) per limited partner unit:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.00
1.00
Weighted average limited partners’ units outstanding:
—
—
—
67.0
$
9.8
$
38.6
0.61
$ (0.20) $
0.98
0.61
$ (0.20) $
0.96
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,709
49,777
47,693
41,407
31,143
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,736
49,851
47,875
41,407
31,853
Cash distributions paid per unit . . . . . . . . . . . . . . . . . . . . .
$
2.60
$
2.44
$
2.28
$
2.14
$
1.91
35
Balance Sheet Data (end of period):
Total assets(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total debt, including current portion . . . . . . . . . . . . . . . .
Partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Financial Data:
Adjusted EBITDA (unaudited) . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . .
Net cash provided by (used in) financing activities . . . . .
Maintenance capital expenditures(a) (unaudited) . . . . . . . .
Other Operating Data (unaudited):
Retail propane gallons sold . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale propane gallons delivered . . . . . . . . . . . . . . . .
Reconciliation of Net Income to EBITDA and
Adjusted EBITDA:
2009
2008
2007
2006
2005
$2,133.1
1,093.3
799.4
$2,077.3
1,106.6
637.8
$1,722.9
710.2
741.2
$1,606.9
659.7
676.1
$1,485.6
559.7
663.9
$ 296.8
239.4
(230.6)
(14.5)
8.0
$ 239.0
183.8
(386.7)
212.5
5.4
$ 211.2
167.9
(187.8)
15.6
5.1
$ 175.4
104.4
(210.9)
109.0
3.7
$ 111.5
87.6
(840.6)
760.1
3.6
310.0
380.6
331.9
358.5
362.2
383.9
360.3
365.3
318.4
391.3
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 101.4
$
65.1
$
67.0
$
9.8
$
38.6
Interest of non-controlling partners in ASC’s
ITDA(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . .
Interest expense, net
. . . . . . . . . . . . . . . . . . . . . . . . .
Write-off of deferred financing costs . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . .
(0.5)
0.7
69.7
—
115.8
(0.8)
0.7
60.9
—
98.0
—
0.7
52.0
—
83.4
—
0.7
53.8
—
76.7
—
0.1
34.2
7.0
50.3
EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash (gain) loss on derivative contracts . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . .
$ 287.1
1.4
5.2
3.1
$ 223.9
0.1
11.5
3.5
$ 203.1
(0.6)
8.0
0.7
$ 141.0
20.0
11.5
2.9
$ 130.2
(19.4)
0.7
—
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 296.8
$ 239.0
$ 211.2
$ 175.4
$ 111.5
(a) Maintenance capital expenditures are defined as those capital expenditures that do not increase operating capacity or revenues from
(b)
(c)
existing levels.
ITDA—Interest, taxes, depreciation and amortization.
These amounts differ from those previously presented as a result of our adoption of FASB Accounting Standards Codification
Subtopic 210-20 on October 1, 2008. In conjunction with the adoption of this standard, we elected to change our accounting policy for
derivative instruments executed with the same counterparty under a master netting agreement. This change in accounting policy has been
presented retroactively.
36
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, our belief that our acquisition expertise
should allow us to continue to grow through acquisitions; our belief that we will have adequate propane
supply to support our retail operations; and our belief that our diversification of suppliers will enable us
to meet supply needs; 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 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:
• weather conditions;
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
price and availability of propane, and the capacity to transport to market areas;
the ability to pass the wholesale cost of propane through to our customers;
costs or difficulties related to the integration of the business of our company and its acquisition targets
may be greater than expected;
governmental legislation and regulations;
local economic conditions;
the demand for high deliverability natural gas storage capacity in the Northeast;
the availability of natural gas and the price of natural gas to the consumer compared to the price of
alternative and competing fuels;
our ability to successfully implement our business plan for our natural gas storage facilities;
labor relations;
environmental claims;
competition from the same and alternative energy sources;
operating hazards and other risks incidental to transporting, storing and distributing propane;
energy efficiency and technology trends;
interest rates;
the price and availability of debt and equity financing; and
large customer defaults.
We have described under “Factors That May Affect Future Results of Operations, Financial Condition or
Business” 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.
37
General
We are a Delaware limited partnership formed to own and operate a growing retail and wholesale propane
supply, marketing and distribution business. We also own and operate a growing midstream business that
includes three natural gas storage facilities (“Stagecoach”, “Steuben” and “Thomas Corners”), a liquefied
petroleum gas (“LPG”) storage facility (“Bath”), a natural gas liquids (“NGL”) business and a solution-mining
and salt production company (“US Salt”). We further intend to pursue our growth objectives in the propane
business through, among other things, future acquisitions. Our acquisition strategy focuses on propane companies
that meet our acquisition criteria, including targeting acquisition prospects that maintain a high percentage of
retail sales to residential customers, operating in attractive markets and focusing our operations under established
and locally recognized trade names. Our midstream growth objectives focus both on organically expanding our
existing assets and acquiring future operations that leverage our existing operating platform, produce
predominantly fee-based cash flow characteristics and have future organic or commercial expansion
characteristics.
Both of our operating segments, propane and midstream, are supported by business development personnel
groups employed by the Partnership. These groups’ daily responsibilities include research, sourcing, financial
analysis and due diligence of potential acquisition targets and organic growth opportunities. These employees
work closely with the operators of both of our segments in the course of their work to ensure the appropriate
growth opportunities are pursued. During fiscal 2009, they evaluated approximately 100 potential acquisitions.
We have grown primarily through acquisitions. Since the inception of our predecessor in November 1996
through September 30, 2009, we have acquired 84 companies, 78 propane companies and 6 midstream
businesses, for an aggregate purchase price of approximately $1.8 billion, including working capital, assumed
liabilities and acquisition costs.
In October 2008, we acquired the assets of the Blu-Gas group of companies (“Blu-Gas”), in April 2009, we
acquired the assets of Newton’s Gas Service, Inc. (“Newton’s Gas”) and on June 30, 2009, we acquired the assets
of F.G. White Company, Inc. (“F.G. White”). The aggregate purchase price of these acquisitions, net of cash
acquired, was $11.8 million. The purchase price allocation for these acquisitions has been prepared on a
preliminary basis pending final asset valuation and asset rationalization, and changes are expected when
additional information becomes available. Changes to final asset valuation of prior fiscal year acquisitions have
been included in our consolidated financial statements but are not material.
For the fiscal year ended September 30, 2009, we sold 310.0 million gallons of propane to retail customers and
sold 380.6 million gallons of propane to wholesale customers.
The results of operations discussed below are those of Inergy, L.P. Audited financial statements for Inergy, L.P.
are included elsewhere in this Form 10-K.
The retail propane distribution business is largely seasonal due to propane’s primary use as a heating source in
residential and commercial buildings. As a result, cash flows from operations are generally highest from
November through April when customers pay for propane purchased during the six-month peak heating season of
October through March. Our propane operations generally experience net losses in the six-month, off season of
April through September.
Because a substantial portion of our propane is used in the weather-sensitive residential markets, the
temperatures realized in our areas of operations, particularly during the six-month peak heating season, have a
significant effect on our financial performance. In any given area, warmer-than-normal temperatures will tend to
result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater
propane use. Therefore, we use information on normal temperatures in understanding how historical results of
operations are affected by temperatures that are colder or warmer than normal and in preparing forecasts of
38
future operations, which are based on the assumption that normal weather will prevail in each of our operating
regions. “Heating degree days” are a general indicator of how weather impacts propane usage and are calculated
for any given period by adding the difference between 65 degrees and the average temperature of each day in the
period (if less than 65 degrees). While a substantial portion of our propane is used by our customers for heating
needs, our propane operations are geographically diversified and not all of our propane sales are weather
sensitive. Together, these factors may make it difficult to draw definitive conclusions as to the correlation of our
gallon sales to weather calculations comparing weather in a year to normal or to the prior year.
In determining actual and normal weather for a given period of time, we compare the actual number of heating
degree days for the period to the average number of heating degree days for a longer, historical time period
assumed to more accurately reflect the average normal weather, in each case as such information is published by
the National Oceanic and Atmospheric Administration, for each measuring point in each of our regions. When
we discuss “normal” weather in our results of operations presented below we are referring to a 30-year average
consisting of the years 1979 through 2009. We then calculate weighted averages, based on retail volumes
attributable to each measuring point, of actual and normal heating degree days within each region. Based on this
information, we calculate a ratio of actual heating degree days to normal heating degree days, first on a regional
basis consistent with our operational structure and then on a partnership-wide basis.
The retail propane business is a “margin-based” business where the level of profitability is largely dependent on
the difference between sales prices and product costs. Propane prices have continued to be volatile during
2009. At the main pricing hub of Mount Belvieu Texas during the fiscal year ended September 30, 2009, propane
prices ranged from a low of $0.53 per gallon to a high of $1.41 per gallon and a price of $0.94 per gallon at
September 30, 2009. Our ability to pass on price increases to our customers and our hedging program limits the
impact that such volatility has had on our results from operations. In the future, we will continue to hedge
virtually 100% of our exposure from fixed price sales. While we have historically been successful in passing on
any price increases to our customers, there can be no guarantees that this trend will continue in the future. In
periods of increasing costs, we have experienced a decline in our gross profit as a percentage of revenues. In
addition, during those periods we have historically experienced conservation of propane gallons used by our
customers which has resulted in a decline in gross profit. In periods of decreasing costs, we have experienced an
increase in our gross profit as a percentage of revenues. There is no assurance that because propane prices decline
customers will use more propane and thus historical gallon sales declines we have attributed to customer
conservation will reverse. The prices of crude oil and natural gas had maintained historically high costs in
calendar year 2007 and 2008 before falling in late 2008 and somewhat leveling off in early 2009 and, since
propane is a by-product of these commodities, it too has been at historically high levels over this same time
frame. As such, our selling prices of propane have been at higher levels in order to attempt to maintain our
historical gross margin per gallon. We do not attempt to predict or control the underlying commodity prices;
however, we monitor these prices daily and adjust our operations and retail prices to maintain expected margins
by passing on the wholesale costs to end users of our product. We believe that volatility in commodity prices will
continue, and our ability to adjust to and manage our operations in response to this volatility may impact our
operations and financial results.
We believe that the economic downturn that began in the second half of 2008 has caused certain of our retail
propane customers to conserve and thereby purchase less propane. This trend is expected to continue throughout
the life of the economic downturn. In addition, although we believe the economic downturn has not currently had
a material impact on our cash collections, it is possible that a prolonged economic downturn could have a
negative impact on our future cash collections.
We believe our wholesale supply, marketing and distribution business complements our retail distribution
business. Through our wholesale operations, we distribute propane and also offer price risk management services
to propane retailers, resellers and other related businesses as well as energy marketers and dealers, through a
variety of financial and other instruments, including:
•
forward contracts involving the physical delivery of propane;
39
•
•
swap agreements which require payments to (or receipt of payments from) counterparties based on the
differential between a fixed and variable price for propane; and
options, futures contracts on the New York Mercantile Exchange and other contractual arrangements.
We engage in derivative transactions to reduce the effect of price volatility on our product costs 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 wholesale customers.
However, we may experience net unbalanced positions from time to time.
Our midstream operations primarily include the storage, processing, fractionation and sale of natural gas and
NGLs and, to a lesser extent, the wholesale distribution of salt from solution mining operations of US Salt, which
was acquired in August 2008. The cash flows from these operations are predominantly fee-based under one to ten
year contracts with substantial, creditworthy counterparties and, therefore, are generally economically stable and
not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations.
We believe our midstream operations 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. However, we also believe
that the predominately contractual fee-based nature of our midstream operations may serve to mitigate this potential
risk.
The majority of our operating cash flows in our midstream operations are generated by our natural gas storage
operations. Most of our natural gas storage revenues are based on regulated market-based tariff rates, which are
driven in large part by competition and demand for our storage capacity and deliverability. Demand for storage in
our key midstream market in the northeastern United States 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. The natural gas industry is currently
experiencing a significant shift in the sources of supply, and this dramatic change could affect our operations.
Traditionally, supply to our markets has come from the Gulf Coast region, onshore and offshore, as well as from
Canada. The national supply profile is shifting to new sources of natural gas from basins in the Rockies,
Mid-Continent, Appalachia and East Texas. In addition, the natural gas supply outlook includes new LNG
regasification facilities under various stages of development in multiple locations. LNG can be a new source of
potential supply, but the timing and extent of incremental supply ultimately realized from LNG is yet to be
determined and, at present, LNG remains a small percentage of the overall supply to the markets we serve. These
supply shifts and other changes to the natural gas market may have an impact on our storage operations and our
development plans in the northeastern United States and may ultimately drive the need for more domestic
capacity for natural gas storage. Currently, we have committed to capital expansion projects at our Finger Lakes
LPG storage expansion. The Finger Lakes LPG storage expansion project relates to the development of certain
caverns acquired in the acquisition of US Salt in August 2008. The solution mining process creates caverns that
can be developed into LPG or Natural Gas storage after the salt has been extracted. The Finger Lakes LPG
expansion project is expected to convert certain of the caverns at US Salt into LPG storage with a capacity of up
to 5 million barrels. This project is expected to be completed in spring 2010.
As we execute on our strategic objectives, capital expansion projects will continue to be an important part of our
growth plan. We have committed capital and investment expenditures at September 30, 2009, of $10.4 million in
our midstream operations. These capital requirements, along with the refinancings of normal maturities of
existing debt, will require us to continue long-term borrowings. An inability to access capital at competitive rates
could adversely affect our ability to implement our strategy. Market disruptions or a downgrade in our credit
ratings may increase the cost of borrowing or adversely affect our ability to access one or more sources of
liquidity. During the past several years, capital expansion projects have been exposed to cost pressures associated
with the availability of skilled labor and the pricing of materials. Although certain costs have begun to decrease,
there will be continual focus on project management activities to address these pressures as we move forward
with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately
earned on current and future expansions.
40
Our midstream operations in the United States are subject to regulations at the federal and state level.
Regulations applicable to the gas storage industry have a significant effect on the nature of our midstream
operations and the manner in which they operate. Changes to regulations are ongoing and we cannot predict the
future course of changes in the regulatory environment or the ultimate effect that any future changes will have on
our midstream operations.
Results of Operations
Fiscal Year Ended September 30, 2009 Compared to Fiscal Year Ended September 30, 2008
The following table summarizes the consolidated income statement components for the fiscal years ended
September 30, 2009 and 2008, respectively (in millions):
Year Ended
September 30,
Change
2009
2008
In Dollars
Percentage
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of product sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,570.6
996.9
$1,878.9
1,376.7
$(308.3)
(379.8)
(16.4)%
(27.6)
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating and administrative expenses . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes and interest of non-controlling partners
in ASC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated net
573.7
279.6
115.8
5.2
173.1
(69.7)
0.1
103.5
(0.7)
502.2
265.6
98.0
11.5
127.1
(60.9)
1.0
67.2
(0.7)
71.5
14.0
17.8
(6.3)
46.0
(8.8)
(0.9)
36.3
—
14.2
5.3
18.2
(54.8)
36.2
(14.4)
(90.0)
54.0
—
income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1.4)
(1.4)
—
—
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 101.4
$
65.1
$ 36.3
55.8%
The following table summarizes revenues, including associated volume of gallons sold, for the years ended
September 30, 2009 and 2008, respectively (in millions):
Revenues
Gallons
Year Ended
September 30,
Change
Year Ended
September 30,
Change
2009
2008
In Dollars
Percent
2009
2008
In Units
Percent
$ 736.7
387.7
209.2
$ 840.7
546.1
223.0
$(104.0)
(158.4)
(13.8)
(12.4)% 310.0
380.6
(29.0)
—
(6.2)
331.9
358.5
—
(21.9)
22.1
—
(6.6)%
6.2
—
Retail propane . . . . . . . . . . . . . . . .
Wholesale propane . . . . . . . . . . . .
Other retail . . . . . . . . . . . . . . . . . . .
Storage, fractionation and other
midstream . . . . . . . . . . . . . . . . .
237.0
269.1
(32.1)
(11.9)
—
—
—
—
Total . . . . . . . . . . . . . . . . . . . . . . . .
$1,570.6
$1,878.9
$(308.3)
(16.4)% 690.6
690.4
0.2 — %
Volume. During fiscal 2009, we sold 310.0 million retail gallons of propane, a decrease of 21.9 million gallons or
6.6% from the 331.9 million retail gallons of propane sold during fiscal 2008. Gallons sold during fiscal 2009
declined compared to fiscal 2008 as a result of lower volumes sold at our existing locations of 35.1 million
gallons partially offset by a 13.2 million gallon increase from acquisition-related volume. Although the weather
41
in our areas of operations was 7% colder than the prior year period when compared to our calculations using
degree day data provided by NOAA, the increase in gallon sales associated with this colder weather was more
than offset by (1) continued customer conservation, which we believe resulted primarily from the lingering
effects of the higher cost of propane that existed at the end of our fiscal year 2008, as well as the overall weak
United States economic environment, and (2) volume declines from net customer losses during the periods of
high propane costs, including low margin and less profitable customers.
Wholesale gallons delivered increased 22.1 million gallons, or 6.2%, to 380.6 million gallons in fiscal 2009 from
358.5 million gallons in fiscal 2008. The increase was due primarily to greater volumes sold to existing
customers and addition of new customers.
The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 10.8 million
gallons, or 4.2%, to 269.9 million gallons in fiscal 2009 from 259.1 million gallons in fiscal 2008. This increase
was primarily attributable to renewal of certain customer contracts and the addition of new contracts.
During fiscal 2009 and 2008, our Northeast natural gas and LPG storage facilities were 100% contracted.
Revenues. Revenues in fiscal 2009 were $1,570.6 million, a decrease of $308.3 million, or 16.4% from $1,878.9
million in fiscal 2008.
Revenues from retail propane sales were $736.7 million for the year ended September 30, 2009, a decrease of
$104.0 million, or 12.4%, compared to $840.7 million for the year ended September 30, 2008. This decrease
resulted primarily from a combination of a lower overall average selling price of propane due to a reduction in
the wholesale cost of propane and a decline in gallons sold to existing customers as described above, which
together contributed to a $136.3 million revenue decline, partially offset by acquisition-related sales, which
resulted in higher revenues of $32.3 million.
Revenues from wholesale propane sales were $387.7 million in fiscal 2009, a decrease of $158.4 million or
29.0%, from $546.1 million in fiscal 2008. This decrease resulted primarily from the lower average selling price
of propane, which contributed $192.0 million to the decrease in revenues. The lower selling price for our
wholesale propane sales in fiscal 2009 compared to fiscal 2008 was the result of the lower cost of propane. This
decrease was partially offset by increases in volume sold to existing and new customers.
Revenues from other retail sales, which primarily include distillates, service, rental, appliance sales and
transportation services, were $209.2 million in fiscal 2009, a decrease of $13.8 million, or 6.2% from $223.0
million in fiscal 2008. Revenues from other retail sales decreased $56.0 million due to lower distillate sales from
existing locations and a decline in other revenues of $5.9 million, partially offset by higher revenues of $48.1
million attributable to acquisitions. The decrease in distillate revenues at existing locations was the result of
lower volume sold coupled with a decline in the comparable average selling price of the distillates resulting from
a lower wholesale cost.
Revenues from storage, fractionation and other midstream activities were $237.0 million in fiscal 2009, a
decrease of $32.1 million or 11.9% from $269.1 million in fiscal 2008. Revenues from our West Coast NGL
operations decreased $81.3 million primarily as a result of decreases in commodity cost and expected changes in
the variety of natural gas liquid products sold. Partially offsetting this decrease was a $44.2 million increase due
to the acquisition of US Salt. In addition, revenues at our Bath LPG Storage Facility and Stagecoach Storage
Facility increased due to an increase in contractual rates and the commencement of operations on the Stagecoach
North Lateral connecting to Millennium Pipeline in December 2008.
Cost of Product Sold. Cost of product sold for fiscal 2009 was $996.9 million, a decrease of $379.8 million, or
27.6%, from $1,376.7 million in fiscal 2008.
42
Retail propane cost of product sold was $373.6 million for the year ended September 30, 2009, compared to
$527.9 million for the year ended September 30, 2008. This $154.3 million, or 29.2%, decrease in retail propane
cost of product sold was driven by an approximate 25% decline in the average per gallon cost of propane along
with lower volume sales at our existing locations as discussed above, which together reduced costs $169.7
million. These factors were partially offset by a $14.1 million increase in the cost of product sold associated with
acquisition-related volume and a $1.3 million increase in cost of product sold related to changes in non-cash
charges on derivative contracts associated with retail propane fixed price sales contracts.
Wholesale propane cost of product sold in fiscal 2009 was $363.8 million, a decrease of $161.3 million or 30.7%,
from wholesale cost of product sold of $525.1 million in fiscal 2008. These lower costs were primarily a result of
a $193.6 million decrease due to the lower average cost of propane. This decrease was partially offset by
increases in volume sold to existing and new customers.
Other retail cost of product sold was $124.8 million for the year ended September 30, 2009, compared to $146.6
million for the year ended September 30, 2008. This $21.8 million, or 14.9%, decrease was primarily due to a
$57.1 million reduction in cost of product sold related to distillate sales at existing locations due to both declines
in volumes sold and the average cost of product. Also contributing to the decline in other retail cost of product
sold was a reduction in costs related to other products and services of $1.9 million. These factors were partially
offset by higher costs associated with acquisitions of $37.2 million.
Storage, fractionation and other midstream cost of product sold was $134.7 million, a decrease of $42.4 million,
or 23.9%, from $177.1 million in fiscal 2008. Costs from our West Coast NGL operations were $76.0 million
lower primarily as a result of decreases in commodity cost and expected changes in the variety of natural gas
liquid products sold. Partially offsetting this decrease was a $28.2 million increase in cost due to the acquisition
of US Salt.
Our retail and wholesale cost of product sold consists primarily of tangible products sold including all propane,
distillates and other natural gas liquids 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 amounted to $62.0 million and $67.0
million for fiscal 2009 and 2008, respectively. In addition, the depreciation expense associated with the delivery
vehicles and customer tanks is reported within depreciation and amortization expense and amounted to $33.0
million in fiscal 2009 and 2008. 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 $36.9 million and $27.7 million for fiscal 2009 and 2008,
respectively. Vehicle costs combined with wages for personnel directly involved in providing midstream services
amounted to $2.7 million and $3.3 million for fiscal 2009 and 2008, 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. Gross profit for fiscal 2009 was $573.7 million, an increase of $71.5 million, or 14.2%, from
$502.2 million during fiscal 2008.
43
Retail propane gross profit was $363.1 million in fiscal 2009, an increase of $50.3 million, or 16.1%, compared
to $312.8 million in fiscal 2008. This increase in retail propane gross profit was mostly attributable to a higher
cash margin per gallon, which contributed an increase to gross profit of $66.5 million, and an increase of $18.2
million associated with acquisitions, partially offset by a $33.1 million decline in gross profit resulting from
lower retail gallon sales at existing locations as discussed above and a $1.3 million decline related to changes in
non-cash charges on derivative contracts associated with retail propane fixed price sales contracts. The increase
in cash margin per gallon was primarily the result of our selling price of propane declining at a slower rate in
certain markets than the underlying cost of propane declined.
Wholesale propane gross profit was $23.9 million in fiscal 2009 compared to $21.0 million in fiscal 2008, an
increase of $2.9 million or 13.8%. This increase was primarily the result of both increased volumes sold and
higher margins that we were able to attain in certain regions where supply disruption occurred in 2009.
Other retail gross profit was $84.4 million for the year ended September 30, 2009, compared to $76.4 million for
the year ended September 30, 2008. This $8.0 million, or 10.5%, increase was due primarily to a $10.9 million
increase from acquisitions and a $1.1 million increase in distillate gross profit, partially offset by a $4.0 million
decline in gross profit for other products and services.
Storage, fractionation and other midstream gross profit was $102.3 million in fiscal 2009 compared to $92.0
million in fiscal 2008, an increase of $10.3 million, or 11.2%. Approximately $16.0 million of this increase was
due to the acquisition of US Salt, which was partially offset by a decrease in gross profit from our West Coast
NGL operations. The decrease in West Coast gross profit is partially attributable to losses taken on certain
commodity contracts due to a brief delay in our butane isomerization unit being placed in service. The
aforementioned isomerization unit was placed in service in July 2009. The decrease is also attributable to the
non-renewal of certain customer contracts.
Operating and Administrative Expenses. Operating and administrative expenses were $279.6 million in fiscal
2009 compared to $265.6 million in fiscal 2008. This $14.0 million, or 5.3%, increase in operating expenses was
due primarily to acquisitions and incentive compensation, which increased $16.1 million and $8.5 million,
respectively. Offsetting these increases were lower operating expenses from existing operations of $10.6 million
comprised predominantly of lower salaries, vehicle expenses and other operating expenses.
Depreciation and Amortization. Depreciation and amortization increased to $115.8 million in fiscal 2009 from
$98.0 million in fiscal 2008. This $17.8 million, or 18.2%, increase was primarily the result of acquisitions and
completed expansion projects being placed into service in our midstream segment.
Loss on Disposal of Assets. Loss on disposal of assets decreased $6.3 million, or 54.8%, to $5.2 million in fiscal
2009 compared to $11.5 million in fiscal 2008. The losses recognized in fiscal 2009 and 2008 include losses of
$4.9 million and $11.5 million, respectively, related to assets held for sale, which have been written down to their
estimated selling price. In addition, we had other losses in fiscal 2009 of $0.3 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 2009 and 2008, these assets were identified primarily as a result of losses due to
disconnecting customer installations of unprofitable accounts due to low margins, poor payment history or low
volume usage.
Interest Expense. Interest expense increased to $69.7 million in fiscal 2009 compared to $60.9 million in fiscal
2008. This $8.8 million, or 14.4%, increase was due to a $220.1 million increase in average debt outstanding
associated with acquisitions and capital improvement projects, partially offset by lower average interest rates
associated with our floating rate debt and benefits from our interest rate swap agreements. Additionally, during
fiscal 2009 and 2008, we capitalized $14.8 million and $5.5 million, respectively, of interest related to certain
capital improvement projects in our midstream segment as further described below in the “Liquidity and Sources
of Capital—Capital Resource Activities” section.
44
Interest of non-controlling partners in ASC’s consolidated net income. We acquired a majority interest in the
operations of Steuben when we acquired 100% of the membership interest in ASC in October 2007. ASC holds a
majority interest in the operations of Steuben.
Net Income. Net income for fiscal 2009 was $101.4 million compared to net income for fiscal 2008 of $65.1
million. The $36.3 million, or 55.8%, increase in net income is primarily attributable to higher gross profit,
partially offset by higher operating expenses, depreciation and amortization and interest expense in fiscal 2009.
EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal
years ended September 30, 2009 and 2008, respectively (in millions):
Year Ended
September 30,
2009
2008
EBITDA:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated ITDA(a)
. . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$101.4
(0.5)
69.7
0.7
115.8
$ 65.1
(0.8)
60.9
0.7
98.0
EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$287.1
$223.9
Non-cash loss on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.4
3.1
5.2
0.1
3.5
11.5
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$296.8
$239.0
(a)
ITDA—Interest, taxes, depreciation and amortization.
Year Ended
September 30,
2008
2009
EBITDA:
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net changes in working capital balances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs and net bond discount . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated EBITDA . . . . . . . . . . . . . . . . .
Interest expense, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$239.4
(3.6)
(3.7)
(5.2)
(3.1)
(5.2)
(1.9)
69.7
0.7
$183.8
3.7
(5.7)
(2.3)
(3.5)
(11.5)
(2.2)
60.9
0.7
EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$287.1
$223.9
Non-cash loss on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.4
3.1
5.2
0.1
3.5
11.5
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$296.8
$239.0
EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense.
For the years ended September 30, 2009 and 2008, EBITDA was $287.1 million and $223.9 million,
respectively. This $63.2 million improvement in EBITDA was primarily attributable to net higher gross profit,
45
which more than offset the increase in cash operating expenses in 2009. 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, the gain or loss on the disposal of assets and non-cash compensation expenses.
Adjusted EBITDA was $296.8 million for fiscal 2009 compared to $239.0 million in fiscal 2008. 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 and Adjusted EBITDA provide additional
information for evaluating our financial performance without regard to our financing methods, capital structure
and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information
for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental
measures. 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.
Fiscal Year Ended September 30, 2008 Compared to Fiscal Year Ended September 30, 2007
The following table summarizes the consolidated income statement components for the fiscal years ended
September 30, 2008 and 2007, respectively (in millions):
Year Ended
September 30,
Change
2008
2007
In Dollars
Percentage
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of product sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,878.9
1,376.7
$1,483.1
1,026.1
$395.8
350.6
26.7%
34.2
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating and administrative expenses . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes and interest of non-controlling partners
in ASC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated net
income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
502.2
265.6
98.0
11.5
127.1
(60.9)
1.0
67.2
(0.7)
(1.4)
457.0
247.8
83.4
8.0
117.8
(52.0)
1.9
67.7
(0.7)
—
45.2
17.8
14.6
3.5
9.3
(8.9)
(0.9)
(0.5)
—
(1.4)
9.9
7.2
17.5
43.8
7.9
(17.1)
(47.4)
(0.7)
—
*
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
65.1
$
67.0
$ (1.9)
(2.8)%
*
not meaningful
The following table summarizes revenues, including associated volume of gallons sold, for the years ended
September 30, 2008 and 2007, respectively (in millions):
Revenues
Gallons
Year Ended
September 30,
Change
Year Ended
September 30,
Change
2008
2007
In Dollars
Percent
2008
2007
In Units
Percent
Retail propane . . . . . . . . . . . . . . . . .
Wholesale propane . . . . . . . . . . . . .
Other retail . . . . . . . . . . . . . . . . . . . .
Storage, fractionation and other
midstream . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . .
$ 840.7
546.1
223.0
$ 733.2
417.2
168.8
269.1
$1,878.9
163.9
$1,483.1
$107.5
128.9
54.2
105.2
$395.8
14.7% 331.9
358.5
30.9
—
32.1
362.2
383.9
—
—
64.2
26.7% 690.4
—
746.1
(30.3)
(25.4)
—
—
(55.7)
(8.4)%
(6.6)
—
—
(7.5)%
46
Volume. During fiscal 2008, we sold 331.9 million retail gallons of propane compared to 362.2 million retail
gallons of propane during fiscal 2007. This 30.3 million gallon, or 8.4%, net decline was due primarily to
customer conservation, which we believe has resulted, in large part, from the higher average cost of Mt. Belvieu
propane. The average cost of Mt. Belvieu propane increased 49% during fiscal 2008 as compared to fiscal 2007.
To a lesser extent, volume declines arising from a loss of less profitable customers and fewer gallon sales to
lower margin customers, including agricultural sales, contributed to the decline in gallons sold during the year.
Also contributing to the decline was the warmer weather during fiscal 2008, which, on average for our operating
areas, was slightly warmer than fiscal 2007 and 7% warmer than normal. These factors that resulted in a decrease
in comparable gallon sales were partially offset by acquisition-related volume, which resulted in an increase of
12.2 million gallons during fiscal 2008 compared to fiscal 2007.
Wholesale gallons delivered decreased 25.4 million gallons, or 6.6%, to 358.5 million gallons in fiscal 2008 from
383.9 million gallons in fiscal 2007. This change was primarily attributable to decreased sales volumes to
existing customers.
The total natural gas liquid gallons sold or processed by our West Coast NGL operations increased 68.8 million
gallons, or 36.2%, to 259.1 million gallons in fiscal 2008 from 190.3 million gallons in fiscal 2007. This increase
was attributable to the addition of natural gas liquid marketing and processing contracts in fiscal 2008.
Stagecoach had 26.25 bcf of working gas storage capacity during fiscal year 2008. Stagecoach had 13.25 bcf of
working gas storage capacity for the first six months in fiscal 2007, 17.45 bcf of working gas storage capacity for
the following five months and 26.25 bcf of working gas storage capacity during September 2007. Stagecoach’s
storage services were 100% contracted during each of the periods noted above. Steuben, which we acquired a
controlling interest in October 2007, had 6.2 bcf of working gas storage capacity and the storage services were
100% contracted during fiscal 2008. The Bath LPG Storage Facility had a storage capacity of 1.7 million barrels
and storage services were 100% contracted during fiscal 2008 and fiscal 2007.
Revenues. Revenues in fiscal 2008 were $1,878.9 million, an increase of $395.8 million, or 26.7% from $1,483.1
million in fiscal 2007.
Revenues from retail propane sales were $840.7 million for the year ended September 30, 2008, an increase of
$107.5 million, or 14.7%, compared to $733.2 million for the year ended September 30, 2007. These higher retail
propane revenues were primarily the result of the higher average selling price of propane and acquisition-related
sales, which contributed $162.8 million and $30.8 million, respectively, to the year over year increase. These
factors were partially offset by an $86.1 million reduction in retail propane revenues arising from lower retail
volume sales at our existing locations as discussed above.
Revenues from wholesale propane sales were $546.1 million in fiscal 2008, an increase of $128.9 million or
30.9%, from $417.2 million in fiscal 2007. Approximately $156.4 million of this increase was attributable to the
higher sales price of propane partially offset by lower sales volumes to existing customers. The higher selling
price in our wholesale division in 2008 compared to 2007 is the result of the increased cost of propane.
Revenues from other retail sales, which primarily include distillates, service, rental, appliance sales and
transportation services, were $223.0 million in fiscal 2008, an increase of $54.2 million, or 32.1% from $168.8
million in fiscal 2007. This increase was primarily related to $39.3 million of acquisition-related sales, a $13.3
million increase in distillate revenues from existing locations and a $4.1 million increase in transportation
revenues. Distillate revenues increased during fiscal 2008 due primarily to a 35% increase in the average selling
price. These increases were partially offset by a $2.5 million decline related to other products and services,
primarily appliances and retail services.
Revenues from storage, fractionation and other midstream activities were $269.1 million in fiscal 2008, an
increase of $105.2 million or 64.2% from $163.9 million in fiscal 2007. Revenues from our West Coast NGL
47
operations were $67.1 million higher as a result of increases in commodity cost and expected changes in the
variety of natural gas liquid products sold due to additional contracts and $7.8 million was due to increased
transportation and processing activities. Additionally, $30.3 million of this increase was due to the acquisitions of
US Salt and ASC, the Stagecoach Phase II expansion being placed into partial service in April 2007 and full
service in September 2007, and increased contractual rates on the Stagecoach Storage Facility and Bath LPG
Storage Facility.
Cost of Product Sold. Cost of product sold for fiscal 2008 was $1,376.7 million, an increase of $350.6 million, or
34.2%, from $1,026.1 million in fiscal 2007.
Retail propane cost of product sold was $527.9 million for the year ended September 30, 2008 compared to
$419.3 million for the year ended September 30, 2007. This $108.6 million, or 25.9%, increase in retail propane
cost of product sold was driven by a 37% higher average per gallon cost of propane, which resulted in a $137.1
million increase in cost. Also contributing to the higher cost of product sold during fiscal 2008 was an increase of
$20.1 million associated with acquisition-related volume and a $0.7 million increase due to changes in non-cash
charges related to derivative contracts associated with retail propane fixed price sales contracts. These factors,
which increased retail propane cost of product sold, were partially offset by lower volume sales at our existing
locations as discussed above, which reduced costs by $49.3 million.
Wholesale propane cost of product sold in fiscal 2008 was $525.1 million, an increase of $124.4 million or
31.0%, from wholesale cost of product sold of $400.7 million in fiscal 2007. Contributing to these higher costs
was a $150.9 million increase due to the higher average cost of propane partially offset by lower volumes sold to
existing customers.
Other retail cost of product sold was $146.6 million for the year ended September 30, 2008 compared to $100.0
million for the year ended September 30, 2007. This $46.6 million, or 46.6% increase was primarily due to
higher costs of $31.9 million related to acquisitions, an increase of $13.4 million associated with distillate sales
from existing locations and a $3.0 million increase in transportation costs. These increases to cost of product sold
were partially offset by a $1.7 million decline in costs for other products and services, primarily appliances sales.
Storage, fractionation and other midstream cost of product sold was $177.1 million, an increase of $71.0 million,
or 66.9%, from $106.1 million in fiscal 2007. Costs from our West Coast NGL operations were $64.4 million
higher as a result of increases in commodity cost and expected changes in the variety of natural gas liquid
products sold due to additional contracts and $5.6 million was due to increased transportation and processing
activities. The remaining increase resulted from the acquisitions of ASC and US Salt, partially offset by lower
power and transportation costs at our Stagecoach facility.
Our retail cost of product sold consists primarily of tangible products sold including all propane, distillates and
other natural gas liquids sold and all propane-related appliances sold. Other costs incurred in conjunction with
the distribution of these products are included in operating and administrative expense 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 amounted to $67.0 million and $63.1 million in 2008 and 2007,
respectively. In addition, the depreciation expense associated with the delivery vehicles and customer tanks is
reported within depreciation and amortization expense and amounted to $33.0 million and $32.3 million in 2008
and 2007, respectively. Since we include these costs in our operating and administrative expenses and
depreciation and amortization expenses 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 consist primarily of depreciation,
vehicle costs consisting of fuel costs and repair and maintenance and wages are included in operating and
administrative expense and depreciation and amortization expense. Depreciation expense for storage,
48
fractionation and other midstream amounted to $27.7 million and $17.4 million in 2008 and 2007, respectively.
Vehicle costs combined with wages for personnel directly involved in providing midstream services amounted to
$3.3 million and $1.9 million in 2008 and 2007, respectively. Since we include these costs in our operating and
administrative expenses and depreciation and amortization expenses 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. Gross profit for fiscal 2008 was $502.2 million, an increase of $45.2 million, or 9.9%, from $457.0
million during fiscal 2007.
Retail propane gross profit was $312.8 million in fiscal 2008, a decline of $1.1 million, or 0.4%, compared to
$313.9 million in fiscal 2007. During fiscal 2008, gross profit declined by $36.8 million primarily as a result of
lower retail gallon sales at existing locations as discussed above. This decline in gross profit was partially offset
by an increase in gross profit of $25.7 million relating to a higher cash margin per gallon and an increase of
$10.7 million due to acquisitions. The increase in cash margin per gallon was primarily the result of our ability to
raise selling prices in certain markets in excess of the increased cost of propane.
Wholesale propane gross profit was $21.0 million in fiscal 2008 compared to $16.5 million in fiscal 2007, an
increase of $4.5 million or 27.3%. Approximately $5.5 million of this increase was the result of a higher margin
per gallon from our existing business partially offset by decreased wholesale volumes from our existing business.
The improved margin per gallon is primarily the result of a higher average selling price in excess of our
increased cost of propane.
Other retail gross profit was $76.4 million for the year ended September 30, 2008 compared to $68.8 million for
the year ended September 30, 2007. This $7.6 million, or 11.0%, increase was due primarily to acquisitions and
higher transportation sales, which together resulted in an increase to other retail gross profit of $8.5 million.
These increases were partially offset by a combined decrease in gross profit for distillate sales, appliance sales
and other retail services of $0.9 million.
Storage, fractionation and other midstream gross profit was $92.0 million in fiscal 2008 compared to $57.8
million in fiscal 2007, an increase of $34.2 million, or 59.2%. Approximately $29.3 million of this increase was
due to the acquisitions of US Salt and ASC, the Stagecoach Phase II expansion being placed into partial service
in April 2007 and full service in September 2007, and increased contractual rates on the Stagecoach Storage
Facility and Bath LPG Storage Facility. The remaining $4.9 million increase relates to increases in
transportation, processing activities and natural gas liquids gross profit at our West Coast NGL operations.
Operating and Administrative Expenses. Operating and administrative expenses were $265.6 million in fiscal
2008 compared to $247.8 million in fiscal 2007. This $17.8 million, or 7.2%, increase in operating expenses was
primarily the result of higher expenses of $15.7 million arising from acquisitions. The remaining increase
resulted from higher vehicle, insurance and other operating expenses, partially offset by lower wages and other
personnel expenses due to integration efficiencies and lower expenses as a result of lesser volumes sold at
existing locations.
Depreciation and Amortization. Depreciation and amortization increased to $98.0 million in fiscal 2008 from
$83.4 million in fiscal 2007. This $14.6 million, or 17.5%, increase was primarily the result of acquisitions and
the completion of the Stagecoach Phase II expansion project in our midstream segment.
Loss on Disposal of Assets. Loss on disposal of assets increased $3.5 million, or 43.8%, to $11.5 million in fiscal
2008 compared to $8.0 million in fiscal 2007. The losses recognized in fiscal 2008 and 2007 include losses of
$11.5 million and $6.2 million, respectively, related to assets held for sale, which have been written down to their
estimated selling price. In addition, we had other losses in fiscal 2007 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
49
underperforming assets. In fiscal 2008, these assets were identified primarily as a result of losses due to
disconnecting customer installations of unprofitable accounts due to low margins, poor payment history or low
volume usage. In fiscal 2007, these assets were identified primarily as the result of the integration of the larger
retail propane acquisitions closed since November 2004 as we focused on eliminating duplicity in vehicles,
operations, tanks and real estate.
Interest Expense. Interest expense increased to $60.9 million in fiscal 2008 compared to $52.0 million in fiscal
2007. This $8.9 million, or 17.1%, increase was due to a $211.7 million increase in average debt outstanding
associated with acquisitions and capital improvement projects, partially offset by a lower average interest rate in
2008 (7.03%) compared to 2007 (7.73%). Additionally, during fiscal 2008 and 2007, we capitalized $5.5 million
and $3.1 million, respectively, of interest related to certain capital improvement projects in our midstream
segment as further described below in the “Liquidity and Sources of Capital—Capital Resource Activities”
section.
Interest of non-controlling partners in ASC’s consolidated net income. We acquired a majority interest in the
operations of Steuben when we acquired 100% of the membership interest in ASC in October 2007. ASC holds a
majority interest in the operations of Steuben.
Net Income. Net income for fiscal 2008 was $65.1 million compared to net income for fiscal 2007 of $67.0
million. The $1.9 million, or 2.8%, decrease in net income is primarily attributable to higher gross profit, offset
by increased operating and administrative expenses, increased depreciation and amortization expenses and
certain non-cash expenses.
EBITDA and Adjusted EBITDA. The following tables summarize EBITDA and Adjusted EBITDA for the fiscal
years ended September 30, 2008 and 2007, respectively (in millions):
Year Ended
September 30,
2008
2007
EBITDA:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated ITDA(a)
. . . . . . . . . . . . . . . . . .
Interest expense, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 65.1
$ 67.0
(0.8) —
52.0
60.9
0.7
0.7
83.4
98.0
EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$223.9
$203.1
Non-cash (gain) loss on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.1
3.5
11.5
(0.6)
0.7
8.0
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$239.0
$211.2
(a)
ITDA—Interest, taxes, depreciation and amortization.
50
Year Ended
September 30,
2008
2007
EBITDA:
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net changes in working capital balances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs and net bond discount . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated EBITDA . . . . . . . . . . . . . . . . .
Interest expense, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$167.9
(3.1)
(3.3)
(2.4)
(0.7)
(8.0)
$183.8
3.7
(5.7)
(2.3)
(3.5)
(11.5)
(2.2) —
52.0
60.9
0.7
0.7
EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$223.9
$203.1
Non-cash (gain) loss on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.1
3.5
11.5
(0.6)
0.7
8.0
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$239.0
$211.2
EBITDA is defined as income before taxes, plus net interest expense and depreciation and amortization expense.
For the years ended September 30, 2008 and 2007, EBITDA was $223.9 million and $203.1 million,
respectively. This $20.8 million improvement in EBITDA was primarily attributable to net higher gross profit,
which more than offset the increase in cash operating expenses in 2008. 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, the gain or loss on the disposal of assets and non-cash compensation expenses.
Adjusted EBITDA was $239.0 million for fiscal 2008 compared to $211.2 million in fiscal 2007. 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 and Adjusted EBITDA provide additional
information for evaluating our financial performance without regard to our financing methods, capital structure
and historical cost basis. Further, we believe that EBITDA and Adjusted EBITDA provide additional information
for evaluating our ability to make the minimum quarterly distribution and are presented solely as supplemental
measures. 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.
Liquidity and Sources of Capital
Capital Resource Activities
On March 23, 2006, our shelf registration statement (File No. 333-132287) was declared effective by the
Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership
securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, we are
permitted to issue these securities from time to time for general business purposes, including debt repayment,
future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus
supplement. In June 2006 and February 2007, we issued 4,312,500 common units (which included 562,500
common units issued as a result of the underwriters exercising their over-allotment provision) and 3,450,000
common units (which included 450,000 common units issued as result of the underwriters exercising their over-
allotment provision), respectively. In March 2009 we issued 4,000,000 common units and in April 2009 we
issued an additional 418,000 common units as a result of the underwriters exercising their over-allotment
provision. In August 2009 we issued 3,500,000 common units and in September 2009 we issued an additional
525,000 common units as a result of the underwriters exercising their over-allotment provision. The proceeds
from these issuances were primarily utilized to pay down borrowings under our credit facility.
51
On September 10, 2009, our new shelf registration statement (File No. 333-158066) was declared effective by the
Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership
securities and debt securities, or any combination thereof.
Cash Flows and Contractual Obligations
Net operating cash inflows were $239.4 million and $183.8 million for fiscal years ending September 30, 2009
and 2008, respectively. The $55.6 million increase in operating cash flows was primarily attributable to increases
in cash components of net income as well as net changes in working capital balances.
Net investing cash outflows were $230.6 million and $386.7 million for the fiscal years ending September 30,
2009 and 2008, respectively. Net cash outflows were primarily impacted by a $203.0 million decrease in cash
outlays related to acquisitions, partially offset by a $22.3 million decrease in proceeds from the sale of assets and
a $24.7 million increase in capital expenditures.
Net financing cash inflows (outflows) were $(14.5) million and $212.5 million for the fiscal years ending
September 30, 2009 and 2008, respectively. The net change was primarily impacted by a $397.5 million decrease
in proceeds related to the issuance of long-term debt, net of payments on long-term debt, and a $28.3 million
increase in total distributions paid, partially offset by a $201.2 million increase in proceeds from the issuance of
common units.
Net operating cash inflows were $183.8 million and $167.9 million for fiscal years ending September 30, 2008
and 2007, respectively. The $15.9 million increase in operating cash flows was primarily attributable to increases
in cash components of net income as well as net changes in working capital balances.
Net investing cash outflows were $386.7 million and $187.8 million for the fiscal years ending September 30,
2008 and 2007, respectively. Net cash outflows were primarily impacted by a $115.5 million increase in cash
outlays related to acquisitions and a $99.2 million increase in capital expenditures, partially offset by a $16.2
million increase in proceeds from the sale of assets.
Net financing cash inflows were $212.5 million and $15.6 million for the fiscal years ending September 30, 2008
and 2007, respectively. Net cash inflows were primarily impacted by a $330.4 million increase in proceeds
related to the issuance of long-term debt, net of payments on long-term debt, a $104.5 million decrease in the
proceeds from issuance of common units, a $3.5 million increase in payments for deferred financing costs, a $2.6
million decrease in proceeds from unit option exercises and a $22.9 million increase in total distributions paid.
At September 30, 2009 and 2008, we had goodwill of $374.3 million and $443.0 million, respectively, representing
18% and 21% of total assets in each year, respectively. This goodwill is attributable to our acquisitions. The net
decrease in goodwill is attributable to certain purchase accounting adjustments made during 2009.
At September 30, 2009, we were in compliance with all debt covenants to our credit facilities.
The following table summarizes our contractual obligations as of September 30, 2009 (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) . . . . . . . . . . . . . . . . . . . . . . .
Future minimum lease payments under noncancelable
operating leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed price purchase commitments(c)
. . . . . . . . . . . . . . . . . .
Standby letters of credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . .
Purchase commitments of identified growth projects(b)
$1,553.3
$100.7
$174.0
$160.7
$1,117.9
38.8
225.3
16.7
10.4
10.1
220.1
16.4
10.4
14.0
5.2
0.3
—
8.5
—
—
—
6.2
—
—
—
Total contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . .
$1,844.5
$357.7
$193.5
$169.2
$1,124.1
52
(a) $181.4 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 2.0% and 3.5% at September 30, 2009. These rates have been
applied for each period presented in the table.
Identified growth projects related to the Thomas Corners and Finger Lakes midstream assets.
(b)
(c) Fixed price purchase commitments are offset by sales contracts that are included in our cash flow hedging program as discussed in Note
2, and the remainder are offset volumetrically with fixed price sale contracts.
We believe that anticipated cash from operations and borrowing capacity under our Credit Agreement described
below 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. We give no assurance that we
can raise additional capital to meet these needs. Global financial markets and economic conditions have been,
and continue to be, disrupted and volatile. The debt and equity capital markets have been distressed, but we have
successfully raised over $200 million in long-term unsecured debt and over $200 million in two separate equity
transactions during 2009. We have identified capital expansion project opportunities in our midstream
operations. Additional commitments or expenditures, if any, we may make toward any one or more of these
projects is at the discretion of the Partnership. Any discontinuation of the construction of these projects will
likely result in less future cash flow and earnings than we have previously indicated.
Description of Credit Facility
On December 17, 2004, we entered into a 5-Year Credit Agreement (the “Credit Agreement”) with our existing
lenders in addition to others. The Credit Agreement consists of a $75 million revolving working capital facility
(“Working Capital Facility”) and a $350 million revolving acquisition facility (“Acquisition Facility”). The
effective amount of working capital borrowing capacity available to us under the two facilities is $200 million
utilizing capacity under the acquisition credit facility for working capital needed during the winter heating
season. Lehman Commercial Paper, Inc. (“Lehman CP”), a subsidiary of Lehman Brothers Holdings, Inc., holds
a $25 million lender commitment within our Credit Agreement and filed for Chapter 11 Bankruptcy on
October 5, 2008. We do not plan for the Lehman lender commitment to be available for the remainder of the term
of the Credit Agreement. The Credit Agreement accrues interest at either prime rate or LIBOR plus applicable
spreads, resulting in interest rates between 2.0% and 3.5% at September 30, 2009. At September 30, 2009,
borrowings outstanding under the Credit Agreement were $27.2 million, with the entire balance borrowed for
working capital purposes. The Credit Agreement is guaranteed by each of our wholly-owned domestic
subsidiaries.
During each fiscal year beginning October 1, the outstanding balance of the Working Capital Facility must be
reduced to $10.0 million or less for a minimum of 30 consecutive days during the period commencing March 1
and ending September 30 of each calendar year. We met this provision of our Credit Agreement in May 2009.
At our option, loans under the Credit Agreement bear interest at either the prime rate or LIBOR (preadjusted for
reserves), plus, in each case, an applicable margin. The applicable margin varies quarterly based on its leverage
ratio. We also pay a fee based on the average daily unused commitments under the Credit Agreement.
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. Any such mandatory prepayments are first applied to reduce borrowings under the
Acquisition Facility and then under the Working Capital Facility.
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);
53
• 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;
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 $20 million in any fiscal year ($40 million under the new
facility discussed in Item 1);
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 $425 million 6.875% senior notes due December 15, 2014 that were issued on December 22, 2004;
our $200 million 8.25% senior notes due March 1, 2016 that were issued on January 11, 2006;
our $200 million 8.25% senior notes due March 1, 2016 that were issued on April 29, 2008;
our $225 million 8.75% senior notes due March 1, 2015 that were issued on February 2, 2009;
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 is less than 5.0 to 1.0 on a pro forma basis;
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 6.875%, 8.25% and 8.75% senior notes and other substantially similar
debt, the debt does not contain covenants more restrictive than those in the Credit Agreement.
54
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
5.25 to 1.0 for any period of two consecutive fiscal quarters immediately following an acquisition with a
purchase price in excess of $100 million and 4.75 to 1.0 at all other times; 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.
At September 30, 2009, our ratio of total funded debt to consolidated EBITDA was 3.60 to 1.0, and our ratio of
consolidated EBITDA to consolidated interest expense was 4.59 to 1.0.
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 $2.5 million (to the extent not covered by insurance) against us or any of our
subsidiaries are undischarged or unstayed for 30 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.
As discussed in Item 1, we now have a $450 million general partnership revolving credit facility for acquisitions,
capital expenditures and general partnership purposes and a $75 million revolving working capital facility.
Senior Unsecured Notes
2014 Senior Notes
On December 22, 2004, we and our wholly-owned subsidiary, Inergy Finance Corp (“Finance Corp.” and
together with us, the “Issuers”) completed a private placement of $425 million in aggregate principal amount of
our 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”). We used the net proceeds from the 2014
Senior Notes to repay all amounts drawn under a 364-day credit facility which was entered into in order to fund
the acquisition of Star Gas and is no longer available to us, with the $39.9 million remaining balance of the net
proceeds applied to the Acquisition Facility.
The 2014 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment
with all other present and future senior indebtedness of ours. The 2014 Senior Notes are effectively subordinated
to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness and to all
existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries. The
2014 Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.
The 2014 Senior Notes are fully, unconditionally, jointly and severally guaranteed by all of our wholly-owned
domestic subsidiaries. The subsidiaries guarantees rank equally in right of payment with all of the existing and
future senior indebtedness of our guarantor subsidiaries. The subsidiaries guarantees are effectively subordinated
to all existing and future secured indebtedness of our guarantor subsidiaries to the extent of the value of the
55
assets securing that indebtedness and to all existing and future indebtedness and other liabilities, including trade
payables, of our non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us). The
subsidiaries guarantees rank senior in right of payment to all of our future subordinated indebtedness.
In October 2005, we completed an offer to exchange our existing 2014 Senior Notes for $425 million of 6.875%
senior notes due 2014 (the “2014 Exchange Notes”) that are registered and do not carry transfer restrictions,
registration rights and provisions for additional interest. The 2014 Exchange Notes did not provide us with any
additional proceeds and satisfied our obligations under the registration rights agreement.
The 2014 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after December 15,
2009, in each case at the redemption prices described in the table below, together with any accrued and unpaid
interest to the date of the redemption.
Year
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
103.438%
102.292%
101.146%
100.000%
2016 Senior Notes
On January 11, 2006, we and our wholly-owned subsidiary, Inergy Finance Corp, issued $200 million aggregate
principal amount of 8.25% senior unsecured notes due 2016 (the “2016 Senior Notes”) in a private placement to
eligible purchasers.
The 2016 Senior Notes contain covenants similar to our existing senior unsecured notes due 2014. We used the
net proceeds of the offering to repay outstanding indebtedness under our revolving acquisition credit facility. The
2016 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of payment with all
other present and future senior indebtedness of ours. The 2016 Senior Notes are fully, unconditionally, jointly
and severally guaranteed by all of our wholly-owned domestic subsidiaries.
On May 18, 2006, we completed an offer to exchange our existing 8.25% 2016 Senior Notes for $200 million of
8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer
restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide
us with any additional proceeds and satisfied our obligations under the registration rights agreement.
The 2016 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2011,
in each case at the redemption prices described in the table below, together with any accrued and unpaid interest
to the date of the redemption.
Year
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
104.125%
102.750%
101.375%
100.000%
In April 2008, we issued an additional $200 million of senior unsecured notes as an add-on to our existing 8.25%
Senior Unsecured Notes due 2016 under Rule 144A to eligible purchasers. The notes mature on March 1, 2016.
The proceeds from the bond issuance were $204 million, representing a 2% premium to par value. On
September 16, 2008, we completed an offer to exchange the additional $200 million of 8.25% senior notes due
2016 for $200 million of 8.25% senior notes due 2016 (the “Additional 2016 Exchange Notes”) that are
registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The
Additional 2016 Exchange Notes did not provide us with any additional proceeds and satisfied our obligations
under the registration rights agreement.
56
2015 Senior Notes
On February 2, 2009, we and our wholly-owned subsidiary, Inergy Finance Corp, issued $225 million aggregate
principal amount of 8.75% senior unsecured notes due 2015 (the “2015 Senior Notes”) under Rule 144A to
eligible purchasers. The 8.75% notes mature on March 1, 2015, and were issued at 90.191% of the principle
amount to yield 11%.
The 2015 Senior Notes contain covenants similar to our existing senior unsecured notes due 2014 and 2016. We
used the net proceeds of the offering to repay outstanding indebtedness under our revolving acquisition credit
facility. The 2015 Senior Notes represent senior unsecured obligations of ours and rank pari passu in right of
payment with all other present and future senior indebtedness of ours. The 2015 Senior Notes are fully,
unconditionally, jointly and severally guaranteed by all of our wholly-owned domestic subsidiaries.
On October 7, 2009, we completed an offer to exchange our existing 8.75% 2015 Senior Notes for $225 million
of 8.75% senior notes due 2015 (the “2015 Exchange Notes”) that are registered and do not carry transfer
restrictions, registration rights and provisions for additional interest. The 2015 Exchange Notes did not provide
us with any additional proceeds and satisfied our obligations under the registration rights agreement.
The 2015 Senior Notes are redeemable, at our option, in whole or in part, at any time on or after March 1, 2013,
in each case at the redemption prices described in the table below, together with any accrued and unpaid interest
to the date of the redemption.
Year
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
104.375%
100.000%
The indentures governing our senior unsecured notes discussed above are substantially similar and contain
covenants that, among other things, will limit our ability and the ability of our restricted subsidiaries to:
•
•
sell assets;
pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
• make investments;
•
•
•
•
•
•
incur or guarantee additional indebtedness or issue preferred units;
create or incur certain liens;
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates; and
create unrestricted subsidiaries.
These covenants are subject to important exceptions and qualifications, and if the notes achieve an investment
grade rating from either Moody’s or Standard & Poor’s, many of these covenants will terminate.
In addition, the indentures governing our senior notes restrict our ability to pay cash distributions. Before we can
pay a distribution to our unitholders, we must demonstrate that the fixed charge coverage ratio (as defined in the
senior notes indentures) is at least 1.75 to 1.0.
Recent Accounting Pronouncements
FASB Accounting Standards Codification Subtopic 825-10 (“825-10”), originally issued as SFAS No. 159, “The
Fair Value Option for Financial Assets and Financial Liabilities”, was issued in February 2007 to permit entities
57
to choose to measure many financial instruments and certain other items at fair value at specified election dates.
A business entity is required to report unrealized gains and losses on items for which the fair value option has
been elected in earnings at each subsequent reporting date. We adopted 825-10 on October 1, 2008. The adoption
of 825-10 did not have an impact on our financial statements.
FASB Accounting Standards Codification Subtopic 820-10 (“820-10”), originally issued as SFAS No. 157, “Fair
Value Measurements”, was issued in September 2006 to define fair value, establish a framework for measuring
fair value according to generally accepted accounting principles and expand disclosures about fair value
measurements. We adopted 820-10 on October 1, 2008. The adoption of 820-10 required certain additional
footnote disclosures, however, it did not have a significant impact on any amounts comprising the consolidated
balance sheets, consolidated statements of operations, consolidated statements of partners’ capital or the
consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 210-20 (“210-20”), originally issued as FASB Staff Position
No. FIN 39-1, “Amendment of FASB Interpretation No. 39”, was issued in April 2007 to permit companies to
offset fair value amounts recognized for the right to reclaim cash collateral (a receivable), or the obligation to
return cash collateral (a payable), against fair value amounts recognized for derivative instruments executed with
the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted
to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments
under master netting arrangements. We adopted 210-20 on October 1, 2008 and elected to change our accounting
policy for derivative instruments executed with the same counterparty under a master netting agreement. 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. This change in accounting policy has been presented
retroactively. The adoption of 210-20 had the following impact on the September 30, 2008 consolidated balance
sheet (in millions):
Assets from price risk management activities . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities from price risk management activities . . . . . . . . . . . . . . . . .
$79.2
46.1
89.5
96.5
97.7
$(45.9)
(24.2)
(20.6)
(8.8)
(40.7)
$33.3
21.9
68.9
87.7
57.0
Original Value Adjustment Adjusted Value
FASB Accounting Standards Codification Subtopic 815-10 (“815-10”), originally issued as SFAS No. 161,
“Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133”
was issued in March 2008 and applies to all derivative instruments and related hedged items. 815-10 requires
entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, results of operations and cash flows. We adopted 815-10 on
March 31, 2009. The adoption of 815-10 required certain additional disclosures, however, it did not impact any
amounts comprising the consolidated balance sheets, consolidated statements of operations, consolidated
statements of partners’ capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 805-10 (“805-10”), originally issued as SFAS No. 141
(revised 2007), “Business Combinations”, was issued in December 2007 and establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. 805-10
also establishes disclosure requirements designed to enable users to evaluate the nature and financial effects of
the business combination. 805-10 is required to be adopted by us for business combinations for which the
acquisition date is on or after October 1, 2009.
58
FASB Accounting Standards Codification Subtopic 810-10 (“810-10”), originally issued as SFAS No. 160,
“Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”, was issued in
December 2007 and requires that accounting and reporting for minority interests will be recharacterized as
non-controlling interests and classified as a component of equity. 810-10 also establishes reporting requirements
that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the
interests of the non-controlling owners. 810-10 applies to all entities that prepare consolidated financial
statements, except not-for-profit organizations, but will affect only those entities that have an outstanding
non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. 810-10 is required to be
adopted by us for the fiscal quarter ended December 31, 2009. We are evaluating the potential financial
statement impact of 810-10 to our consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as EITF Issue No. 07-4,
“Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”, was
ratified in March 2008 and applies to Master Limited Partnerships (“MLP”) that are required to make incentive
distributions when certain thresholds have been met regardless of whether the IDR is a separate limited partner
(“LP”) interest or embedded in the general partner interest. 260-10 addresses how the current period earnings of
an MLP should be allocated to the general partner, LP’s and, when applicable, IDR’s. 260-10 is required to be
adopted by us for the fiscal quarter ended December 31, 2009. We are evaluating the potential financial
statement impact of 260-10 to our consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as FSP EITF Issue
No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating
Securities”, was ratified in June 2008 and applies to the calculation of earnings per share (“EPS”) under FASB
Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as SFAS 128, “Earnings Per
Share”, for share-based payment awards with rights to dividends or dividend equivalents. 260-10 states that
unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are
participating securities and shall be included in the computation of EPS pursuant to the two-class method. 260-10
is required to be adopted by us for the fiscal quarter ended December 31, 2009. We are evaluating the potential
financial statement impact of 260-10 to our consolidated financial statements.
In May 2009, the FASB issued FASB Accounting Standards Codification Subtopic 855-10 (“855-10”), originally
issued as SFAS No. 165, “Subsequent Events”. 855-10 establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before financial statements are issued or are
available to be issued. We adopted 855-10 on June 30, 2009. The adoption of 855-10 required us to disclose the
date through which subsequent events have been evaluated and the basis for that date. The adoption of 855-10
did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations,
consolidated statements of partners’ capital or the consolidated statements of cash flows.
In June 2009, the FASB issued FASB Accounting Standards Codification Subtopic 105-10 (“105-10”), originally
issued as SFAS 168, “The FASB Accounting Standards Codification and Hierarchy of Generally Accepted
Accounting Principles”, to supersede FASB Statement No. 162, “The Hierarchy of Generally Accepted
Accounting Principles”, and reorganize the standards applicable to financial statements of nongovernmental
entities that are presented in conformity with GAAP. The purpose of the codification was to provide a single
source of authoritative nongovernmental GAAP literature. The codification was not intended to create new
accounting standards or guidance. While the codification includes portions of SEC content related to matters
within the basic financial statements for user convenience, it does not contain all SEC guidance on accounting
topics, and does not replace any SEC rules or regulations. We adopted 105-10 on September 30, 2009. The
adoption of 105-10 did not impact any amounts comprising the consolidated balance sheets, consolidated
statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash
flows.
59
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 propane and
heating oil will be available; and (iii) manage our exposure to interest rate risk. We record all derivative
instruments on the balance sheet as either assets or liabilities measured at estimated fair value.
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 or the
dollar offset method 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 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.
These 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. Any
ineffective portion of the fair value hedges is recognized as cost of product sold in the current period. We
recognized a $0.2 million net gain in the year ended September 30, 2009, related to the ineffective portion of our
fair value hedging instruments. In addition, for the year ended September 30, 2009, 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. 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. Any ineffective portion of the gain or loss is recognized as cost of product sold in
the current period. Accumulated other comprehensive income (loss) was $11.0 million and $(25.3) million at
September 30, 2009 and 2008, respectively. Approximately $11.7 million is expected to be reclassified to
earnings from other comprehensive income over the next twelve months.
60
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.
If management’s assumptions related to unobservable inputs used in the pricing models for our financial
instruments, which include swaps, forwards, futures and options, are inaccurate or if we had used an alternative
valuation methodology, the estimated fair value may have been different, and we may be exposed to unrealized
losses or gains. A hypothetical 10% difference in the assumptions made for our unobservable inputs would have
impacted our estimated fair value of these derivatives at September 30, 2009, and would have affected net
income by an immaterial amount for the year ended September 30, 2009.
Revenue Recognition. Sales of propane, other liquids and salt are recognized at the time product is shipped or
delivered to the customer. 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 later of the time of sale or
installation. Revenue from repairs and maintenance is recognized upon completion of the service. Revenue from
storage contracts is recognized during the period in which storage services are provided.
Impairment of 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, 2009. 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. Due to the
economic uncertainty, we adjusted our assumptions underlying our discounted cash flow approach to valuing
enterprise value. Projected cash flows for 2010 reflect the deteriorating economic conditions that began in the
latter half of 2008. The discount rate used in the current year reflects an increase in our cost of capital due to the
dislocation of worldwide credit markets. 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. To date, we have not recognized any impairment on assets we have
acquired.
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. A 10% decrease in the estimated net realizable value would have
resulted in an additional loss of $0.2 million at September 30, 2009.
Self-Insurance. We are insured by third parties, 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, general, product and vehicle liability, and environmental
exposures. 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. At September 30, 2009
and 2008, our self-insurance reserves were $19.3 million and $17.4 million, respectively.
61
Factors That May Affect Future Results of Operations, Financial Condition or Business
• We may not be able to generate sufficient cash from operations to allow us to pay the minimum
quarterly distribution.
• Our future acquisitions and completion of our expansion projects will require significant amounts of
debt and equity financing which may not be available to us on acceptable terms, or at all.
•
•
Since weather conditions may adversely affect the demand for propane, our financial condition and
results of operations are vulnerable to, and will be adversely affected by, warm winters.
If we do not continue to make acquisitions on economically acceptable terms, our future financial
performance will be reliant upon internal growth and efficiencies.
• We cannot assure you that we will be successful in integrating our recent acquisitions.
•
Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect
our profit margins.
• Our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders or
capitalize on acquisition or other business opportunities.
•
•
The highly competitive nature of the retail propane business could cause us to lose customers, thereby
reducing our revenues.
If we are not able to purchase propane from our principal suppliers, our results of operations would be
adversely affected.
• Competition from alternative energy sources may cause us to lose customers, thereby reducing our
revenues.
• Our business would be adversely affected if service at our principal storage facilities or on the common
carrier pipelines we use is interrupted.
• We are subject to operating and litigation risks that could adversely affect our operating results to the
extent not covered by insurance.
• Our results of operations and financial condition may be adversely affected by governmental regulation
and associated environmental regulatory costs.
•
Energy efficiency and new technology may reduce the demand for propane.
• Due to our lack of asset diversification, adverse developments in our propane business would reduce our
ability to make distributions to our unitholders.
See “Item 1A—“Risk Factors” for further discussion of factors that could impact our business.
62
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
We have long-term debt and a revolving line of credit subject to the risk of loss associated with movements in
interest rates. At September 30, 2009, we had floating rate obligations totaling $181.4 million including amounts
borrowed under our Credit Agreement, the ASC Credit Agreement and interest rate swaps, which convert a
portion of our fixed rate senior unsecured notes due 2014 to floating, with aggregate notional amounts of $150
million. The floating rate obligations expose us to the risk of increased interest expense in the event of increases
in short-term interest rates.
If the floating rate were to fluctuate by 100 basis points from September 2009 levels, our combined interest
expense would change by a total of approximately $1.8 million per year.
Certain counterparties have elected to call their respective interest rate swap positions. The aggregate notional
amount associated with these swaps amounts to $125 million. These swaps will be called in December 2009 and
we are currently evaluating our options to manage our interest rate risk.
Commodity Price, Market and Credit Risk
Inherent in our contractual portfolio 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, 2009 and 2008, were propane
retailers, resellers, energy marketers and dealers.
The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices
over supply costs. As a result, our profitability will be sensitive to changes in wholesale prices of propane caused
by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale
cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale
prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to supply or
other market conditions. We have no control over supply or market conditions. In addition, the timing of cost
pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our
gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail
customers to conserve or convert to alternative energy sources.
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 wholesale 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.
63
Fair Value
The fair value of the derivatives and inventory exchange contracts related to price risk management activities as
of September 30, 2009, and September 30, 2008, was assets of $23.8 million and $33.3 million, respectively and
liabilities of $29.3 million and $57.0 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 negligible change in the
market value of the contracts as there were (0.1) million gallons of net unbalanced positions at September 30,
2009.
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, 2009, 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) or in other factors during the period ended
September 30, 2009, that have materially affected, or are reasonably likely to materially affect, our internal
controls over financial reporting.
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 generally accepted accounting principles.
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.
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Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did
not include the operations resulting from the three acquisitions (collectively “the Acquisitions”) which were
acquired during fiscal 2009 and are included in the 2009 consolidated financial statements. The financial
reporting systems of the Acquisitions were integrated into the company’s financial reporting systems throughout
2009. 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 $14.4 million and $10.5 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, 2009. 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, 2009, our internal control over financial reporting is
effective, in all material respects, based upon those criteria.
Our independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated
November 30, 2009 on the effectiveness of our internal control over financial reporting, which is included herein.
Item 9B. Other Information.
None.
65
Item 10. Directors, Executive Officers and Corporate Governance.
Our Managing General Partner Manages Inergy, L.P.
PART III
Inergy GP, LLC, our managing general partner, manages our operations and activities. Our managing general
partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our
managing 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 partners and their affiliates, and we
receive an opinion of counsel regarding limited liability and tax matters. Any removal of the managing general
partner is also subject to the approval of a successor managing 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 managing general partner owes a fiduciary duty to the unitholders. Our managing
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 managing 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 managing general partner and are subject to the oversight of the directors of our managing general partner.
The board of directors of our managing general partner is presently composed of five directors.
Inergy Holdings, L.P. owns our non-managing general partner and our managing general partner. As the sole
member of our managing general partner, Inergy Holdings has the power to elect our board of 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 managing general partner. Executive officers and directors will serve until their successors are
duly appointed or elected.
Executive Officers and Directors
Age
Position with our Managing General Partner
John J. Sherman . . . . . . . . . .
Phillip L. Elbert . . . . . . . . . . .
54
51
President, Chief Executive Officer and Director
President and Chief Operating Officer—Propane Operations and Director
R. Brooks Sherman, Jr. . . . . .
44 Executive Vice President and Chief Financial Officer
Carl A. Hughes . . . . . . . . . . .
Laura L. Ozenberger . . . . . . .
Andrew L. Atterbury . . . . . . .
William R. Moler . . . . . . . . .
55
51
36
43
Senior Vice President—Business Development
Senior Vice President—General Counsel and Secretary
Senior Vice President—Corporate Development
Senior Vice President—Natural Gas Midstream Operations
Warren H. Gfeller . . . . . . . . .
57 Director
Arthur B. Krause . . . . . . . . . .
68 Director
Robert D. Taylor . . . . . . . . . .
62 Director
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John J. Sherman. Mr. Sherman has served as President, Chief Executive Officer and a director since March
2001, 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, which is one of the
country’s largest retail propane marketers. He also serves as President, Chief Executive Officer and director of
Inergy Holdings GP, LLC and a director of Great Plains Energy Inc.
Phillip L. Elbert. Mr. Elbert has served as President and Chief Operating Officer—Propane Operations since
September 2007 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 marketer
from 1981 to 1987. He also serves as the President and Chief Operating Officer—Propane Operations of Inergy
Holdings GP, LLC.
R. Brooks Sherman, Jr. Mr. Brooks Sherman, Jr. (no relation to Mr. John Sherman) has 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 serves as
Executive Vice President and Chief Financial Officer of Inergy Holdings GP, LLC.
Carl A. Hughes. Mr. Hughes has served as Senior Vice President of Business Development since September
2007 and Vice President of Business Development since March 2001. He joined our predecessor as Vice
President of Business Development in 1998. From 1996 through 1998, he served as a regional manager for
Dynegy Inc., responsible for propane activities in 17 midwestern and northeastern states. From 1993 through
1996, Mr. Hughes served as a regional marketing manager for LPG Services Group. From 1985 through 1992,
Mr. Hughes was employed by Ferrellgas where he served in a variety of management positions.
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 serves as Senior Vice President—General Counsel and Secretary of Inergy Holdings GP, LLC.
Andrew L. Atterbury. Mr. Atterbury has served as Senior Vice President—Corporate Development since
September 2007 and Vice President—Corporate Strategy since 2003. Prior to that, Mr. Atterbury served as the
Director of Corporate Development from 2002 to 2003. From 1999 to 2001, Mr. Atterbury worked in the
Corporate Development Group of Kinder Morgan, Inc. and Kinder Morgan G.P., Inc. From 1996 through 1998,
Mr. Atterbury was employed by Lehman Brothers, Inc. in its Real Estate Finance Group.
William R. Moler. Mr. Moler has served as Senior Vice President—Natural Gas Midstream Operations since
September 2007, Vice President of Midstream Operations since 2005 and Director of Midstream Operations
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since 2004. Prior to joining Inergy, Mr. Moler was with Westport Resources Corporation where he served as both
General Manager of Marketing and Transportation Services and General Manager of Westport Field Services,
LLC. Prior to Westport, Mr. Moler served in various leadership positions at Kinder Morgan, Inc.
Warren H. Gfeller. Mr. Gfeller has been a member of our managing 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 natural gas liquids.
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 serves as a director of Inergy Holdings GP, LLC.
Arthur B. Krause. Mr. Krause has been a member of our managing 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 also serves as a
director of Inergy Holdings GP, LLC and Westar Energy.
Robert D. Taylor. Mr. Taylor joined our managing 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.
Independent Directors
Messrs. Gfeller, Krause and Taylor qualify as “independent” in accordance with the published listing
requirements of the NASDAQ Global Select National Market. The NASDAQ independence definition includes a
series of objective tests, such as that the director is not an employee of the company and has not engaged in
various types of business dealings with the company. In addition, as further required by the NASDAQ rules, the
board of directors has made a subjective determination as to each independent director that no relationships exist
which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the
responsibilities of a director.
Board Committees
Audit Committee
The members of the audit committee must meet the independence standards established by the NASDAQ Global
Select National Market. The members of the audit committee are Arthur B. Krause, Warren H. Gfeller and
Robert D. Taylor. The board of directors of our managing general partner has determined 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.
Conflicts Committee
Our managing 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
68
standards for service on an audit committee of a board of directors, which standards are established by the
NASDAQ Global Select National Market. 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 managing general
partner of any duties it may owe us or our unitholders.
Compensation Committee
Two members of the board of directors also serve on a 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.
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 Securities and Exchange Commission initial reports of
ownership and reports of changes in ownership in such securities and other equity securities of our company.
Securities and Exchange Commission 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, 2009, 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. This code of ethics may be found on our website at www.inergypropane.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
managing 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 managing general partner is
determined by the compensation committee of the board of directors of our managing general partner. Certain of
our named executive officers also serve as executive officers of the general partner of Inergy Holdings, L.P. and
the compensation of the named executive officers discussed below reflects total compensation for services to all
Inergy entities. These “shared” officers receive no additional salary or cash compensation for their service to
Inergy Holdings, L.P. However, as discussed in greater detail below, from time to time they do receive awards of
equity in Inergy Holdings, L.P.
Compensation Philosophy and Objectives
We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our
performance is our ability to increase sustainable quarterly 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;
69
•
•
•
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; 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
propane 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.
“Peer” MLP Companies
Amerigas Partners, L.P.
Copano Energy, LLC
Crosstex Energy, L.P.
Regional Companies
Compass Minerals International, Inc.
DST Systems, Inc.
Layne Christensen Company
Energy Transfer Partners, L.P.
Kansas City Southern
Ferrellgas Partners, L.P.
Markwest Energy Partners, L.P.
Suburban Propane Partners, L.P.
70
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 this fiscal year.
In collecting the peer group data for the compensation committee for fiscal 2009, 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 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 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.
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In fiscal 2008, after two years of no changes to base salary amounts, the compensation committee determined it
was appropriate to adjust base salaries. In so doing, the compensation committee primarily considered:
•
•
the increased level of responsibility of each of the named executive officers, which resulted from a
number of acquisitions in fiscal years 2005 through 2007, including the acquisition of the Stagecoach
facility, resulting in the addition of the midstream segment to our business;
the increased complexity in the business, which resulted from:
•
•
the initial public offering of Inergy Holdings, L.P. in fiscal 2005; and
the diversification of business, including the addition of the midstream segment;
•
our financial results during fiscal 2007, including:
• Adjusted EBITDA;
•
•
distributable cash flow; and
distributable cash flow per unit on a fully distributed basis; and
•
the general value of the officers to the company based on increased knowledge of the business and the
industry as a result of tenure with the company.
As a result of those considerations, the base salaries of each of our named executive officers was increased to
$350,000, $225,000, $275,000, $200,000 and $200,000 for John J. Sherman, R. Brooks Sherman, Phillip L.
Elbert, Laura L. Ozenberger and William R. Moler, respectively.
For fiscal 2009, consistent with its general policy of not making systematic annual adjustments to base salary, the
compensation committee elected not to make any changes to the annual base salaries of our named executive
officers.
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 the 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 bonus amount that is up to 100% of the named executive officer’s base salary.
The bonuses payable to the named executive officers in fiscal 2009 were based upon our achievement of two
financial performance metrics: (i) earnings before income taxes, plus net interest expense, depreciation and
amortization expense, further adjusted to exclude the gain or loss on derivative contracts, the gain or loss on the
disposal of fixed assets and long-term incentive and equity compensation expense (“Adjusted EBITDA”) and
(ii) growth in annualized distributions per unit. We have selected these metrics because we believe they closely
align the focus of our named executive officers with the increase in unitholder value. In addition, these were the
targets we communicated to our unitholders and analysts as guidance at the beginning of the 2009 fiscal year.
The financial performance targets were not weighted.
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The following table summarizes the incentive award targets and our actual results for the fiscal year ended
September 30, 2009 (in millions, except per unit data):
$277.0
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted EBITDA(1)
Inergy, L.P. annualized distribution per unit (growth) . . . . . . . . . . . . . . . . . . . . . . . . . .
$2.64(4%)
Inergy Holdings, L.P. annualized distribution per unit (growth) . . . . . . . . . . . . . . . . . . $2.92(12%)
$296.8
$2.70(6%)
$3.40(31%)
(1) Adjusted EBITDA represents EBITDA excluding (1) non-cash gains or losses on derivative contracts associated with fixed price sales to
retail propane customers, (2) non-cash compensation charges and (3) gains or losses on disposals of assets. For a reconciliation of
EBITDA to Adjusted EBITDA refer to page 36 of this annual report on Form 10-K.
Target
Actual
As reflected in the table above, for fiscal year 2009 we exceeded the targets for Adjusted EBITDA and
annualized distribution growth per unit. Accordingly, in accordance with the terms of the employment
agreements of the named executive officers, the compensation committee approved the short-term incentive
awards for fiscal 2009 at 100% of base salary performance. In approving the awards, the compensation
committee also considered that combined annual base salary and annual incentive awards were generally at the
median of our peer companies. Additionally, William R. Moler was awarded a discretionary cash bonus of
$55,000 for his leadership on certain midstream expansion projects.
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 Holdings Long Term Incentive Plan 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 Holdings, L.P. and to provide an incentive to management for continuous
employment with the managing general partner and its affiliates. Long-term incentive compensation is based
upon the common units representing limited partnership interests in us or Inergy Holdings, L.P. and may consist
of unit options or restricted units. 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.
We do not make 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 for both our company and for
Inergy Holdings, 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.
Prior equity awards were made in fiscal 2002, fiscal 2005 and fiscal 2008. Consistent with our general policy of
not making systematic annual awards, no equity awards were made to the named executive officers in fiscal
2009. However, in connection with an amendment to Mr. Moler’s employment agreement, on November 25,
2009, the compensation committee awarded Mr. Moler 37,500 Inergy, L.P. restricted units and 37,500 Inergy
Holdings, L.P. restricted units, which are subject to forfeiture if certain company financial performance metrics
are not met.
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Inergy Long Term Incentive Plan
Our managing 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 managing general partner’s board of directors.
Unit Options
The Inergy Long Term Incentive Plan currently permits, and our managing 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 managing general partner or us.
Generally, unit options will expire after 10 years.
Upon exercise of a unit option, our managing 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 managing general partner, or
any combination of the foregoing. The managing general partner will be entitled to reimbursement by us for the
difference between the cost incurred by the managing general partner in acquiring these common units and the
proceeds received by the managing 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 managing 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 managing 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 managing 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
managing 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 Holdings Long Term Incentive Plan
Inergy Holdings GP, LLC, the general partner of Inergy Holdings, L.P., sponsors the Inergy Holdings 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 of Inergy Holdings GP, LLC.
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Unit Options
The Inergy Holdings Long Term Incentive Plan currently permits, and its 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 granted will become exercisable over a five-year period. In
addition, the unit options will become exercisable upon a change of control of Holdings’ general partner.
Generally, unit options will expire after 10 years.
Upon exercise of a unit option, Holdings’ general partner will acquire common units in the open market, or
directly from Holdings 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 Holdings 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. If Holdings issues new common units
upon exercise of the unit options, the total number of common units outstanding will increase and the general
partner will pay Holdings 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 Holdings Long Term Incentive Plan currently permits, and its 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
Holdings’ general partner’s board of directors in its discretion may terminate the Inergy Holdings Long Term
Incentive Plan at any time with respect to any common units for which a grant has not yet been made. Holdings’
general partner’s board of directors also has the right to alter or amend the Inergy Holdings 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.
75
Perquisites and Other Compensation
We do not provide perquisites or other personal benefits to any of the named executive officers.
Severance 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 a 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,
both the Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan provide for
accelerated vesting 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). Nonetheless, the salaries for each of the named
executive officers are substantially less than the Section 162(m) threshold of $1,000,000 and we believe the
bonus compensation and long-term incentive compensation would qualify for performance-based compensation
under Reg. 1.162-27(e) and therefore would not be additive to salaries for purposes of measuring the $1,000,000
tax limitation.
Compensation Committee Report
We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based
on our review and discussion with management, we have recommended that the Compensation Discussion and
Analysis be included in this Annual Report on Form 10-K for the year ended September 30, 2009.
Warren H. Gfeller
Arthur B. Krause
Members of the Compensation Committee
76
Summary Compensation Table
The following table sets forth the cash and non-cash compensation earned for the years ended September 30,
2009, September 30, 2008, and September 30, 2007 by each person who served as the Chief Executive Officer,
Chief Financial Officer and the three other highest paid executive officers (the “named executive officers”)
during fiscal 2009.
Name and Principal Position
Fiscal
Year
Salary
($)
Bonus
($)
Stock
Awards
($)(1)
Option
Awards
($)(1)
Non-Equity
Incentive Plan
Compensation
($)
All Other
Compensation
($)(3)
Total
($)
John. J. Sherman . . . . . . . . . . . . . . 2009 350,000 —
—
President and Chief Executive
Officer
2008 350,000 — 350,000(2) —
2007 300,000 —
—
— 350,000
—
— 300,000
R. Brooks Sherman, Jr. . . . . . . . . . 2009 225,000 — 138,619
Executive Vice President and
Chief Financial Officer
President and Chief Operating
Officer—Propane Operations
33,464
2008 225,000 — 364,000(2) 13,628
— 12,316
2007 200,000 —
20,868
2008 275,000 — 473,570(2) 20,925
— 20,859
2007 240,000 —
Phillip L. Elbert . . . . . . . . . . . . . . . 2009 275,000 — 198,027
Laura L. Ozenberger . . . . . . . . . . . 2009 200,000 —
2008 200,000 —
2007 175,000 50,000
Senior Vice President, General
Counsel and Secretary
99,014
99,285
33,464
16,339
— 16,225
William R. Moler . . . . . . . . . . . . . 2009 200,000 55,000(4) 99,014
22,382
2008 200,000 — 321,901(2) 11,455
Senior Vice President-Natural
Gas Midstream Operations
225,000
—
200,000
275,000
—
240,000
200,000
200,000
175,000
200,000
—
7,137
5,504
7,888
105,047
86,404
6,060
148,388
123,029
3,690
73,512
64,104
5,944
98,633
90,181
707,137
705,504
607,888
727,130
689,032
418,376
917,283
892,524
504,549
605,990
579,728
422,169
675,029
623,537
(1)
(2)
The amounts included in the “Stock Awards” and “Option Awards” columns reflect the dollar amount of compensation expense we
recognized with respect to these awards for the fiscal year ended September 30, 2009, and include amounts attributable to awards granted
in and prior to fiscal 2009. Assumptions used in the calculation of these amounts are discussed in Note 9 to our consolidated financial
statements. These amounts reflect our accounting expense for these awards, and do not correspond to the actual value that will be
recognized by the named executive officers. The material terms of our outstanding LTIP awards to our executive officers are described in
“Compensation Discussion and Analysis—Long-Term Incentive Plans.”
John J. Sherman, R. Brooks Sherman, Jr., Phillip L. Elbert and William R. Moler were awarded Inergy, L.P. restricted units in an amount
equal to $350,000, $225,000,$275,000 and $200,000, respectively, for their fiscal 2008 annual incentive. The restricted units were
granted on December 1, 2008, with the actual number of restricted units granted based on the closing price of an Inergy, L.P common
unit on such date. The restricted units fully vested on February 4, 2009 (60 days from the grant date).
(3) Consists of: (i) distributions paid on restricted units granted under the Long-Term Incentive Plans (R. Brooks Sherman, Jr.—$99,925,
Phillip L. Elbert—$142,750, Laura L. Ozenberger—$71,375 and William R. Moler—$94,075); (ii) matching contributions to the
partnership’s 401(k) Plan for each named executive officer; and (iii) the partnership’s payment for the benefit of the named executive
officers under the partnership’s group term life insurance policy. The partnership does not provide perquisites and other personal benefits
exceeding a total value of $10,000 to any named executive officer.
(4) As discussed in the Compensation Discussion & Analysis, William R. Moler was awarded a discretionary cash bonus of $55,000 for his
leadership on certain midstream expansion projects.
77
Grants of Plan Based Awards Table
The following table provides information concerning each grant of an award made to our named executive
officers in the last completed fiscal year under any plan, including awards that have been transferred.
Name
Estimated Future Payouts Under
Incentive Plan Awards
Threshold
($)
Target
($)
Maximum
($)(1)
All Other
Stock
Awards(#)(2)
Grant Date Fair
Value of Stock and
Option Awards ($)(2)
John J. Sherman . . . . . . . . . . . . . . . . . . . . . . . .
R. Brooks Sherman, Jr. . . . . . . . . . . . . . . . . . . .
Phillip L. Elbert . . . . . . . . . . . . . . . . . . . . . . . . .
Laura L. Ozenberger . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
William R. Moler
0
0
0
0
0
350,000
225,000
275,000
200,000
200,000
350,000
225,000
275,000
200,000
200,000
22,846
14,687
17,950
—
13,055
350,000
225,000
275,000
—
200,000
(1)
(2)
The “Maximum” amount may be increased by the discretion of the Compensation Committee as described above in the “Compensation
Discussion and Analysis—Incentive Awards.”
The compensation committee awarded John J. Sherman, R. Brooks Sherman, Jr., Phillip L. Elbert and William R. Moler their fiscal 2008
incentive award in Inergy, L.P. restricted units. Although granted in fiscal 2009, these awards are reported in the Summary
Compensation Table in fiscal 2008 because they are part of the named executive officers’ fiscal 2008 incentive compensation.
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
A discussion of fiscal 2009 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, President and Chief Executive Officer;
• R. Brooks Sherman, Jr., Executive Vice President—Chief Financial Officer;
•
•
Phillip L. Elbert, President and Chief Operating Officer—Propane Operations;
Laura L. Ozenberger, Senior Vice President—General Counsel and Secretary; and
• William R. Moler, Senior Vice President—Natural Gas Midstream Operations.
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 either three or five years. During the fiscal year, the annual salaries for
these individuals are as follows:
•
John J. Sherman—$350,000
• R. Brooks Sherman, Jr.—$225,000
•
•
Phillip L. Elbert—$275,000
Laura L. Ozenberger—$200,000
• William R. Moler—$200,000
78
These employees are reimbursed for all expenses in accordance with the managing general partner’s policies.
They are also eligible for fringe benefits normally provided to other employees.
All of the individuals are eligible for annual performance bonuses upon meeting certain established criteria for
each year during the term of his or her employment.
Generally, unless waived by the managing general partner, in order for any of these individuals to receive any
benefits under (i) the Inergy Long Term Incentive Plan and the Inergy Holdings Long Term Incentive Plan, or
(ii) the performance bonus, the individual must have been continuously employed by the managing 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 managing 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.
Effective November 25, 2009, Mr. Moler’s employment agreement was amended to expand the noncompetition
provision and extend the term until November 24, 2014. A copy of the amendment is included herewith as
Exhibit 10.7A.
Outstanding Equity Awards at Fiscal Year-End Table
The following table summarizes the options and restricted units outstanding as of September 30, 2009, for the
named executive officers. The table includes unit options and restricted units of Inergy, L.P. (NASDAQ: NRGY)
granted under the Inergy Long Term Incentive Plan and unit options and restricted units of Inergy Holdings, L.P.
(NASDAQ: NRGP) granted under the Inergy Holdings Long Term Incentive Plan.
Name
Security
OPTION AWARDS
UNIT AWARDS
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
($)(8)
John J. Sherman . . . . . . . . . . . . .
—
—
—
R. Brooks Sherman, Jr. . . . . . . . . NRGY
NRGP
—
20,000(2)
Phillip L. Elbert
. . . . . . . . . . . . . NRGY
NRGP
—
—
Laura L. Ozenberger . . . . . . . . . . NRGY
NRGP
William R. Moler . . . . . . . . . . . . NRGY
NRGY
NRGP
NRGP
22,400(1)
18,000(2)
10,000(4)
—
7,500(6)
2,500(7)
—
20,000(2)
—
40,000(3)
—
20,000(2)
—
5,000(5)
7,500(6)
2,500(7)
—
—
22.50
—
22.50
15.70
22.50
24.14
28.60
22.50
33.33
—
—
—
—
06/19/15
—
06/19/15
02/09/13
06/19/15
07/11/14
09/14/15
06/19/15
09/14/15
—
35,000
—
50,000
—
25,000
7,500
—
25,000
—
—
1,624,000
—
2,320,000
—
1,160,000
223,350
—
1,160,00
—
(1) Option vested in full on February 10, 2008 (5 years from the grant date).
10,000 vested on June 20, 2009 and 20,000 will vest June 20, 2010.
(2)
(3) Option will vest in full on June 20, 2010 (5 years from the grant date).
79
(4) Option vested in full on July 12, 2009 (5 years from the grant date).
(5) Option will vest in full on September 15, 2010 (5 years from the grant date).
(6)
3,750 vested on June 20, 2008, 3,750 vested on June 20, 2009, and the remaining 7,500 will vest on June 20, 2010.
1,250 vested on September 15, 2008, 1,250 vested on September 15, 2009, and the remaining 2,500 will vest on September 15, 2010.
(7)
(8) Market value for NRGY units based on the NASDAQ closing price of $29.78 on September 30, 2009, and market value of NRGP units
based on the NASDAQ closing price of $46.40 on September 30, 2009.
Option Exercises and Stock Vested Table
The following table provides information regarding option exercises and restricted unit vesting during the fiscal
year ended September 30, 2009, for the named executive officers.
Name
Security
Option Awards
Stock Awards
Number
of Units
Acquired
On
Exercise
(#)
Value
Realized
on
Exercise
($)
Number
of Units
Acquired
On
Vesting
(#)
Value
Realized
on
Vesting
($)
John J. Sherman . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NRGY
—
R. Brooks Sherman, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NRGY 20,000
Phillip L. Elbert
—
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NRGY 25,000
Laura L. Ozenberger
—
William R. Moler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NRGY
—
NRGY
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NRGY
213,740
248,288
— 22,846(1) 538,480
14,687(1) 346,173
— 17,950(1) 423,081
—
—
— 13,055(1) 307,706
59,150
—
2,500
(1) Messrs. Sherman, Sherman, Elbert and Moler took their fiscal 2008 annual incentive award payouts in Inergy, L.P. restricted units with
the number based on the cash value of their respective annual incentive awards divided by the NASDAQ closing price of our common
units on such date (December 1, 2008), which units fully vested on February 4, 2009 (60 days from the grant date).
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;
80
•
•
•
•
•
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;
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, 2009, our named executive officers would have been entitled to the following:
•
John J. Sherman would have received $320,833, representing base salary for the remaining 11 months of
the term of his employment agreement (payable bi-monthly in arrears). For two years following the
termination of Mr. Sherman’s employment he will continue to be subject to the non-competition
provisions of his employment agreement.
• R. Brooks Sherman, Jr. would have received $168,750, representing base salary for the remaining 9
months of the term of his employment agreement (payable bi-monthly in arrears). For two years
following termination of Mr. Sherman’s employment he will continue to be subject to the
non-competition provisions of his employment agreement.
•
•
Phillip L. Elbert would have received $68,750, representing base salary for the remaining 3 months of
the term of his employment agreement (payable bi-monthly in arrears). In addition, to receiving
severance payments upon a termination of employment without Cause, Mr. Elbert is entitled to the same
benefits if he terminates his employment for “Good Reason” which is defined as (i) Inergy GP, LLC
requiring, as a condition of employee’s employment, that employee commit a felony or engage in
conduct that is a crime under the Securities Act of 1933, as amended, or the Securities Exchange Act of
1934, as amended; and (ii) employee being required by Inergy GP, LLC to be based at any office or
location that is more than 35 miles from the location where employee was employed immediately
preceding the date of the voluntary or involuntary termination of employee’s employment. For up to two
years following termination of Mr. Elbert’s employment he will continue to be subject to the
non-competition provisions of his employment agreement.
Laura L. Ozenberger would have received $200,000 representing base salary for the remaining 12
months of the term of her employment agreement (payable bi-monthly in arrears). For a minimum of
one year following termination of employment Ms. Ozenberger will continue to be subject to the
non-competition provisions of her employment agreement.
• William R. Moler would have received $400,000 representing base salary for the remaining 24 months
of the term of his employment agreement (payable bi-monthly in arrears). In addition, to receiving
severance payments upon a termination of employment without Cause, Mr. Moler is entitled to the same
benefits if he terminates his employment for “Good Reason” which is defined as (i) employee being
required by Inergy GP, LLC to be based at any office or location that is more than 75 miles from the
location where employee was employed immediately preceding the date of the voluntary or involuntary
termination of employee’s employment, or (ii) a material reduction in employee’s job duties and
responsibilities. For two years following termination of Mr. Moler’s employment he will continue to be
subject to the non-competition provisions of his employment agreement. Effective November 25, 2009,
Mr. Moler’s employment agreement was amended to expand the noncompetition provision and extend
the term until November 24, 2014. A copy of the amendment is included herewith as Exhibit 10.7A.
81
Inergy Long Term Incentive Plan and Inergy Holdings Long Term Incentive Plan
Upon a change in control, all unit options and restricted units 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. For purposes of the Inergy Long Term Incentive Plan and
Inergy Holdings 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.
If a change in control were to have occurred as of September 30, 2009, all unvested awards held by the named
executive officers under the Inergy Long Term Incentive Plan as well as the Inergy Holdings Long Term
Incentive Plan would have automatically vested and become exercisable, as follows:
Option
Awards
under the
Inergy
Long
Term
Incentive
Plan (#)
—
—
—
—
5,000
—
Exercise
Price Per
Share under
the Long
Term
Incentive
Plan ($)
Option
Awards
under the
Inergy
Holdings
Long Term
Incentive
Plan (#)
Exercise
Price Per
Share
under the
Holdings
Long Term
Incentive
Plan ($)
Restricted
Units
under the
Inergy
Long
Term
Incentive
Plan (#)
Restricted
Units Under
the Inergy
Holdings
Long Term
Incentive
Plan (#)
—
—
—
—
28.60
—
—
20,000
40,000
20,000
7,500
2,500
—
22.50
22.50
22.50
22.50
33.33
—
—
—
—
7,500
—
—
35,000
50,000
25,000
25,000
—
Total ($)(1)
—
2,102,000
3,276,000
1,638,000
1,601,175
—
Name
John J. Sherman . . . . . . . . .
R. Brooks Sherman, Jr. . . . .
Phillip L. Elbert . . . . . . . . . .
Laura L. Ozenberger . . . . . .
William R. Moler . . . . . . . .
(1)
For options, the amounts included in the “Total” column are calculated by subtracting the per share exercise price under the options from
the closing per share price of our common units on September 30, 2009 ($29.78), or the closing per share price of the common units of
Holdings ($46.40), as applicable, and multiplying the difference by the number of units subject to the option. For restricted units the
amounts included in the “Total” column are calculated by multiplying the number of restricted units by the closing per share price of our
common units on September 30, 2009 ($29.78), or the closing per share price of the common units of Holdings ($46.40), as applicable.
Director Compensation Table
The following table sets forth the cash and non-cash compensation earned for the year ended September 30,
2009, by each person who served as a non-employee director of Inergy GP, LLC.
Name
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Warren H. Gfeller
Arthur B. Krause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert A. Pascal(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert D. Taylor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fees
Earned
or Paid
in Cash
($)
41,000
44,000
6,250
36,000
Unit
Awards
($)(1)
Option
Awards
($)(1)
All Other
Compensation
($)(2)
25,026 —
25,026 —
—
25,026 —
—
4,788
4,788
1,084
4,788
Total
($)
70,814
73,814
7,334
65,814
(1)
The amounts included in the “Unit Awards” and “Option Awards” columns reflect the dollar amount of compensation expense we
recognized with respect to these awards for the fiscal year ended September 30, 2009, and include amounts attributable to awards granted
in and prior to fiscal 2009. Assumptions used in the calculation of these amounts are discussed in Note 9 to our consolidated financial
statements. These amounts reflect our accounting expense for these awards and do not correspond to the actual value that will be
recognized by the directors.
(2) Dollar value of distributions paid on restricted units during the fiscal year ended September 30, 2009.
(3) Mr. Pascal retired from the board of directors effective December 12, 2008.
82
Compensation of Directors
Officers of our managing general partner who also serve as directors will not receive additional compensation.
Each director receives cash compensation of $25,000 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, audit or conflicts committee meeting attended. The chairman of the audit
committee receives an annual fee of $5,000 per year and the chairman of the compensation committee receives
an annual fee of $1,000 per year. Furthermore, each non-employee director receives an annual grant of restricted
units under the long-term incentive plan equal to $25,000 in value. In April 2009, Messrs. Gfeller, Krause and
Taylor each received 1,126 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. Messrs. Gfeller and Krause also receive compensation for their services on the board of directors of Inergy
Holdings GP, LLC, which is not reflected in the table above.
Compensation Committee Interlocks and Insider Participation
The compensation committee of the board of directors of our managing 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 2009.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters.
The following table sets forth certain information as of October 30, 2009, regarding the beneficial ownership of
our units by:
•
•
•
•
each person who then beneficially owned more than 5% of such units then outstanding;
each of the named executive officers of our managing general partner;
each of the directors of our managing general partner; and
all of the directors and named executive officers of our managing general partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or
5% or more unitholders, as the case may be.
Name of Beneficial Owner(1)
Inergy Holdings, L.P.(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Kayne Anderson MLP Investment Company(3)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1800 Avenue of the Stars, 2nd FL
Los Angeles, CA 90067
John J. Sherman Trusts(4)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Warren H. Gfeller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arthur B. Krause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
William R. Moler
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Robert D. Taylor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Phillip L. Elbert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
R. Brooks Sherman, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Laura L. Ozenberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
All directors and named executive officers as a group (8 persons)
83
Common
Units
Beneficially
Owned
4,706,689
4,002,820
4,843,449
61,839
46,211
17,555
15,466
14,883
12,648
7,467
5,019,518
Percentage
of Common
Units
Beneficially
Owned
7.9%
6.7%
8.1%
*
*
*
*
*
*
*
8.4%
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.
(2) Of the common units indicated as beneficially owned by Inergy Holdings, 2,837,034 units are held by Inergy Partners, LLC, 789,202
units are held by IPCH Acquisition Corp., both wholly-owned subsidiaries of Inergy Holdings, and 1,080,453 units are held directly by
Inergy Holdings.
Information as to the number of common units is furnished in reliance upon the Schedule 13G’s of the corresponding entities or
individuals.
(3)
(4) Mr. Sherman holds an ownership interest in Inergy Holdings through various trusts of which he has voting control. As trustee, Mr. John
Sherman may be deemed to own 4,706,689 common units. Of these units, 789,202 are held by IPCH Acquisition Corp., a wholly-owned
subsidiary of Inergy Holdings L.P. (formerly Inergy Holdings, LLC.), 2,837,034 units are held by Inergy Partners, LLC, of which Inergy
Holdings L.P. (formerly Inergy Holdings, LLC) has 100% voting control, and 1,080,453 common units are held by Inergy Holdings, L.P.
(formerly Inergy Holdings, LLC.). Mr. Sherman disclaims beneficial ownership of the reported securities except to the extent of his
pecuniary interest. The remaining 136,760 common units include the 116,870 units held in a revocable trust by John J. Sherman, the
4,892 units held through the Inergy, L.P. EUPP and 14,998 units that are individually owned.
The following table shows the beneficial ownership as of October 30, 2009, of Inergy Holdings, L.P. of the
directors and named executive officers of our managing general partner, the directors and named executive
officers of the general partner of Inergy Holdings, L.P. and each person who beneficially owned more than 5% of
such units outstanding. As reflected above, Inergy Holdings owns our managing general partner, non-managing
general partner, incentive distribution rights and, through subsidiaries, 7.8% of our outstanding limited partner
units.
Name of Beneficial Owner(1)
John J. Sherman(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Swank Capital, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Andrew L. Atterbury . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
William C. Gautreaux(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Phillip L. Elbert(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
R. Brooks Sherman Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Laura L. Ozenberger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
William R. Moler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Warren H. Gfeller
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Arthur B. Krause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Richard T. O’Brien . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . .
All directors and named executive officers as a group (9 persons)
Inergy Holdings, L.P.
Percent of Class
39.15%
5.74%
5.40%
5.25%
4.47%
1.96%
*
*
*
*
*
46.00%
*
(1)
Less than 1%
The address of each person listed above is Two Brush Creek Boulevard, Suite 200, Kansas City, Missouri 64112.
(2) Mr. Sherman may be deemed to beneficially own 7,936,826 common units held through various trusts, of which Mr. Sherman serves as
either the trustee or co-trustee, and 2,053 units through the Employee Unit Purchase Plan.
(3) Mr. Gautreaux may be deemed to beneficially own 969,471 common units held through various trusts of which Mr. Gautreaux serves as
either the trustee or co-trustee.
(4) Mr. Elbert may be deemed to beneficially own 855,732 common units held through various trusts of which Mr. Elbert serves as either the
trustee or co-trustee.
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.
Related Party Transactions
In connection with our acquisition of assets from United Propane, Inc. on July 31, 2003, we entered into ten
leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business. We
entered into five of these leases with United Propane, three of these leases with Pascal Enterprises, Inc. and two
84
of these leases with Robert A. Pascal. Each of these leases provided for an initial five-year term, and was
renewable by us for up to two additional terms of five years each. During the initial term of these leases we were
required to make monthly rental payments totaling $59,167, of which $17,167 was payable to United Propane,
$16,800 was payable to Pascal Enterprises and $25,200 was payable to Mr. Pascal. During fiscal 2008, we
exercised our renewal option on six of these leases for an additional five-year term each. Three of these leases are
with United Propane, two of these leases are with Mr. Pascal and one is with Pascal Enterprises. We are now
required to make monthly rental payments totaling $50,947 of which $8,400 is payable to United Propane,
$30,997 is payable to Mr. Pascal and $11,550 is payable to Pascal Enterprises. We believe that the monthly rental
payments on the above described leases are consistent with the terms that could have been negotiated with an
unrelated third party.
Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing. Mr. Pascal
retired from our board of directors on December 12, 2008.
On occasion, Inergy Holdings reimburses us for expenses paid on behalf of Inergy Holdings. The expenses that
are reimbursed predominantly include insurance and professional fees. These expenses for the years ended
September 30, 2009, 2008 and 2007, amounted to $0.5 million, $0.2 million and $0.4 million, respectively. When
we have a receivable from Inergy Holdings it is included in prepaid expenses and other current assets on our
consolidated balance sheets. At September 30, 2009 and 2008, we had $0.1 million and $0.2 million,
respectively, due from Inergy Holdings.
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 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.
85
Our managing 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 managing general partner elects to adopt a resolution or a course of action that has not
received Special Approval, then our managing 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 managing 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 managing 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 managing general partner, the resolution,
action or terms so made, taken or provided by the managing 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 managing 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 managing general partner considers the specific facts and circumstances involved. Relevant facts
would include:
•
•
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 managing general partner considers
any facts and circumstances that it deems to be relevant, including:
•
the terms of the transaction, including the aggregate value;
86
•
•
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 managing general partner or the conflicts committee determines in its sole
discretion to be relevant, reasonable or appropriate under the circumstances.
•
•
•
Distributions and Payments to the Managing General Partner and the Non-managing General Partner
Distributions and payments are made by us to our managing general partner and its affiliates in connection with
our ongoing operation. These distributions and payments were determined by and among affiliated entities and
are not the result of arm’s length negotiations.
Cash distributions will generally be made approximately 99% to the limited partner unitholders, including
affiliates of the managing general partner as holders of common units, and approximately 1% to the
non-managing general partner. In addition, when distributions exceed certain target distribution levels, Inergy
Holdings is entitled to receive increasing percentages of the distributions (incentive distribution rights), up to
48% of the distributions above the highest target level.
During fiscal 2009, Inergy Holdings received $48.1 million in distributions related to its 0.8% general partner
interest and incentive distribution rights and $12.3 million related to its 7.8% limited partner interest.
Our managing general partner and its affiliates will not receive any management fee or other compensation for
the management of us. Our managing general partner and its affiliates will be reimbursed, however, for direct
and indirect expenses incurred on our behalf. The expense reimbursement to our managing general partner and its
affiliates was $3.1 million for the fiscal year ended September 30, 2009, and $3.5 million for the fiscal years
ended September 30, 2008 and 2007, with the reimbursement related primarily to personnel costs.
If our managing general partner withdraws in violation of the partnership agreement or is removed for cause, a
successor general partner has the option to buy the general partner interests and incentive distribution rights from
our non-managing general partner for a cash price equal to fair market value. If our managing general partner
withdraws or is removed under any other circumstances, our non-managing general partner has the option to
require the successor general partner to buy its general partner interests and incentive distribution rights for a
cash price equal to fair market value.
If either of these options is not exercised, the general partner interests and incentive distribution rights will
automatically convert into common units equal to the fair market value of those interests. In addition, we will be
required to pay the departing general partner for expense reimbursements.
Upon our liquidation, the partners, including our non-managing general partner, will be entitled to receive
liquidating distributions according to their particular capital account balances.
Rights of our Managing General Partner and our Non-managing General Partner
Inergy Holdings owns an aggregate 8.6% interest in us inclusive of ownership of all of our non-managing general
partner and our managing general partner. Our managing general partner manages our operations and activities.
87
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 annual financial statements and for other services for the years ended September 30, 2009 and 2008
(in millions):
Audit fees(1)
Audit-related fees(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended
September 30,
2009
$ 2.5
—
$ 2.5
2008
$2.2
0.6
$2.8
(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. This category includes fees related to the review of our quarterly and other SEC filings and services related to internal control
assessments.
(2) Audit-related fees consist of due diligence fees associated with acquisition transactions, financial accounting and reporting consultations
and benefit plan audits.
The audit committee of our general partner reviewed and approved all audit and non-audit services provided to us
by Ernst & Young during fiscal year 2009. 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.inergypropane.com.
88
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 Schedule:
Schedule II: Valuation and Qualifying Accounts located on page 134.
Other financial statement schedules have been omitted because they either are 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
*2.1
*2.2
*3.1
*3.1 A
*3.2
*3.2 A
*3.2 B
*3.2 C
*3.3
Description
Purchase Agreement dated as of July 8, 2005, among Inergy Acquisition Company, LLC, Inergy
Storage, Inc., Inergy Stagecoach II, LLC, Stagecoach Holding, LLC, Stagecoach Energy, LLC and
Stagecoach Holding II, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form
8-K filed on July 12, 2005)
Interest Purchase Agreement, dated November 18, 2004, among Star Gas Partners, L.P., Star Gas
LLC, Inergy Propane, LLC and Inergy, L.P. (incorporated herein by reference to Exhibit 2.1 to
Inergy L.P.’s Form 8-K filed on November 24, 2004)
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)
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 (Registration No. 000-32543) filed on May 12,
2003)
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 (Registration No. 000-32453) filed on
February 13, 2004)
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 (Registration
No. 000-32453) filed on May 14, 2004)
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)
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)
Certificate of Formation as relating to Inergy Propane, LLC, as amended (incorporated herein by
reference to Exhibit 3.3 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration
No. 333-56976) filed on May 7, 2001)
89
Exhibit
Number
*3.4
*3.5
*3.6
*3.7
*3.8
*4.1
*4.2
*4.3
*4.4
*4.5
*4.6
*4.7
*4.8
*4.9
*4.10
*10.1
Description
Third Amended and Restated Limited Liability Company Agreement of Inergy Propane, LLC, dated
as of July 31, 2001 (incorporated herein by reference to Exhibit 3.4 to Inergy, L.P.’s Registration
Statement on Form S-1 (Registration No. 333-89010 filed on May 24, 2002)
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)
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)
Certificate of Formation as relating to Inergy Partners, LLC, as amended (incorporated herein by
reference to Exhibit 3.7 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration
No. 333-56976) filed on May 7, 2001)
Second Amended and Restated Limited Liability Company Agreement of Inergy Partners, LLC,
dated as of July 31, 2001 (incorporated herein by reference to Exhibit 3.8 to Inergy, L.P.’s
Registration Statement on Form S-1 (Registration No. 333-89010) filed on May 24, 2002)
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)
Registration Rights Agreement dated as of November 29, 2004 between Inergy, L.P. and Kayne
Anderson MLP Investment Company (incorporated herein by reference to Exhibit 4.1 to Inergy
L.P.’s Form 8-K filed on December 3, 2004)
Registration Rights Agreement dated as of November 29, 2004 between Inergy, L.P. and Tortoise
Energy Infrastructure Corporation (incorporated herein by reference to Exhibit 4.2 to Inergy L.P.’s
Form 8-K filed on December 3, 2004)
Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s
Form 8-K filed on December 27, 2004)
Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.’s Form 8-K filed on
December 27, 2004)
Registration Rights Agreement dated August 9, 2005 between Inergy, L.P. and Inergy Holdings, L.P.
(incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on August 12, 2005)
Registration Rights Agreement (incorporated herein by reference to Exhibit 4.1 to Inergy L.P.’s
Form 8-K filed on January 18, 2006)
Indenture (incorporated herein by reference to Exhibit 4.2 to Inergy L.P.’s Form 8-K filed on
January 18, 2006)
First Supplemental Indenture dated April 24, 2008 (incorporated herein by reference to Exhibit 4.1 to
Inergy, L.P.’s Form 8-K filed on April 29, 2008)
Indenture (incorporated by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on February 3,
2009)
Sixth Amended and Restated Credit Agreement by and among Inergy Propane, LLC and the lenders
named therein, dated as of May 27, 2004 (incorporated herein by reference to Exhibit 10.1 to Inergy,
L.P.’s Form 10-Q (Registration No. 000-32453) filed on August 13, 2004)
90
Exhibit
Number
*10.2
*10.3
*10.4
*10.5
*10.5 A
*10.6
*10.6 A
*10.6 B
Description
Securities Purchase Agreement by and among Inergy Partners, LLC and various investors, dated as
of January 12, 2001 (incorporated herein by reference to Exhibit 10.3 to Inergy, L.P.’s Registration
Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
Investor Rights Agreement by and among Inergy Partners, LLC and various investors, dated as of
January 12, 2001 (incorporated herein by reference to Exhibit 10.4 to Inergy, L.P.’s Registration
Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
Inergy Long Term Incentive Plan (as amended and restated August 14, 2008) (incorporated herein
by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on August 18, 2008)***
Employment Agreement—John J. Sherman (incorporated herein by reference to Exhibit 10.8 to
Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on July 2,
2001)***
First Amendment to Employment Agreement – John J. Sherman (incorporated herein by reference
to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on September 23, 2005)***
Employment Agreement—Phillip L. Elbert (incorporated herein by reference to Exhibit 10.9 to
Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7,
2001)***
First Amendment to Employment Agreement—Phillip L. Elbert (incorporated herein by reference
to Exhibit 10.9A to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No.
333-56976) filed on July 20, 2001)***
Second Amendment to Employment Agreement—Phillip L. Elbert (incorporated herein by
reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q (Registration No. 000-32453 filed on
February 9, 2005)***
*10.7
Employment Agreement—William R. Moler (incorporated by reference to Exhibit 10.7 to Inergy
L.P.’s Form 10-K filed on December 1, 2008)***
**10.7A
First Amendment to Employment Agreement—William R. Moler***
*10.8
*10.9
*10.10
*10.10A
*10.11
*10.12
Employment Agreement—Laura L. Ozenberger (incorporated by reference to Exhibit 10.8 to
Inergy, L.P.’s Form 10-K filed on November 29, 2007)***
Intercreditor and Collateral Agency Agreement entered into as of June 7, 2002, by and among
Wachovia Bank, National Association, the lenders named therein and the noteholders named
therein (incorporated herein by reference to Exhibit 10.19 to Inergy, L.P.’s Registration Statement
on Form S-1/A (Registration No. 333-89010) filed on June 13, 2002)
Employment Agreement—R. Brooks Sherman, Jr. (incorporated herein by reference to Exhibit
10.20 to Inergy, L.P.’s Form 10-K (Registration No. 000-32453) filed on December 26, 2002)***
First Amendment to Employment Agreement, dated as of June 20, 2005, by and between Inergy
GP, LLC and R. Brooks Sherman, Jr. (incorporated herein by reference to Exhibit 10.1 to Inergy,
L.P.’s Form 8-K filed on June 24, 2005)***
Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.11 to Inergy,
L.P.’s Form 10-K filed on November 29, 2007)***
Amended and Restated Inergy Unit Purchase Plan (incorporated by reference to Exhibit 10.1 to
Inergy L.P.’s Form 10-Q filed on February 13, 2004)***
91
Exhibit
Number
*10.13
*10.13A
*10.14
*10.15
*10.16
*10.17
*10.18
*10.19
*10.20
*10.21
*10.22
Description
5-Year Credit Agreement dated as of December 17, 2004, among Inergy, L.P., the lenders party
thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Lehman Commercial Paper, Inc.
and Wachovia Bank, National Association, as Co-Syndication Agents and Fleet National Bank and
Bank of Oklahoma, National Association, as Co-Documentation Agents (incorporated herein by
reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
Amendment to the 5-Year Credit Agreement dated as of December 17, 2004, among Inergy, L.P.,
the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Lehman
Commercial Paper, Inc. and Wachovia Bank, National Association, as Co-Syndication Agents and
Fleet National Bank and Bank of Oklahoma, National Association, as Co-Documentation Agents
(incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on November 14,
2005)
364-Day Credit Agreement dated as of December 17, 2004, among Inergy, L.P., the lenders party
thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Lehman Commercial Paper, Inc.
and Wachovia Bank, National Association, as Co-Syndication Agents and Fleet National Bank and
Bank of Oklahoma, National Association, as Co-Documentation Agents (incorporated herein by
reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
Guaranty dated as of December 17, 2004 among Inergy Propane, LLC, L & L Transportation, LLC,
Inergy Transportation, LLC, Inergy Sales & Service, Inc., Inergy Finance Corp., Inergy Acquisition
Company, LLC, Stellar Propane Service, LLC and Inergy Gas, LLC in favor of JPMorgan Chase
Bank, N.A., as Administrative Agent for the benefit of the Holders of Secured Obligations under
the Credit Agreements (incorporated herein by reference to Exhibit 10.3 to Inergy, L.P.’s Form 8-K
filed on December 22, 2004)
Pledge and Security Agreement dated as of December 17, 2004 among Inergy, L.P. and the other
Subsidiaries of Inergy, L.P. listed on the signature pages thereto and JPMorgan Chase Bank, N.A.,
as administrative agent for the lenders party to the Credit Agreements (incorporated herein by
reference to Exhibit 10.4 to Inergy, L.P.’s Form 8-K filed on December 22, 2004)
Trademark Security Agreement dated as of December 17, 2004 among Inergy, L.P. and the
subsidiaries of Inergy, L.P. listed on the signature page attached thereto and JPMorgan Chase Bank,
N.A., as administrative agent on behalf of itself and on behalf of the Holders of Secured
Obligations under the Credit Agreements (incorporated herein by reference to Exhibit 10.5 to
Inergy, L.P.’s Form 8-K filed on December 22, 2004)
Noncompetition Agreement, dated December 17, 2004, among Inergy Propane, LLC, Star Gas
Partners, L.P. and Star Gas LLC (incorporated herein by reference to Exhibit 10.6 to Inergy, L.P.’s
Form 8-K filed on December 22, 2004)
Special Unit Purchase Agreement dated August 9, 2005 by and between Inergy, L.P. and Inergy
Holdings, L.P. (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on
August 12, 2005)
Common Unit Purchase Agreement dated as of November 29, 2004 between Inergy, L.P. and
Kayne Anderson MLP Investment Company (incorporated herein by reference to Exhibit 10.1 to
Inergy L.P.’s Form 8-K filed on December 3, 2004)
Common Unit Purchase Agreement dated as of November 29, 2004 between Inergy, L.P. and
Tortoise Energy Infrastructure Corporation (incorporated herein by reference to Exhibit 10.2 to
Inergy L.P.’s Form 8-K filed on December 3, 2004)
Asset Purchase Agreement by and among Dowdle Gas, Inc., John Charles Dowdle Investment
Management Trust, J. Nutie Dowdle, John C. Dowdle and Inergy Propane, LLC (incorporated
herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q filed on February 9, 2006)
92
Exhibit
Number
*10.23
Description
Summary of Non-Employee Director Compensation (incorporated herein by reference to Exhibit
10.1 to Inergy, L.P.’s Form 8-K filed on February 14, 2006)***
**12.1
Computation of ratio of earnings to fixed charges
*14.1
Inergy’s Code of Business Ethics and Conduct
**21.1
List of subsidiaries of Inergy, L.P.
**23.1
Consent of Ernst & Young LLP
**31.1
**31.2
**32.1
**32.2
Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
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
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
**99.1
Audited balance sheet of Inergy GP, LLC
Previously filed
*
** Filed herewith
*** 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, 2009 and 2008 and each of the
Three Years in the Period Ended
September 30, 2009
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 Partners’ Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
95
96
97
98
99
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
102
94
Report of Independent Registered Public Accounting Firm
The Board of Directors 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, 2009 and 2008, and the related consolidated statements of operations, partners’ capital and
cash flows for each of the three years in the period ended September 30, 2009. Our audits also included the
financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the
responsibility of the Company’s management. Our responsibility is to express an opinion on these financial
statements and schedule 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, 2009 and 2008, and the consolidated results
of their operations and their cash flows for each of the three years in the period ended September 30, 2009, in
conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial
statement schedule, 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, 2009,
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 30, 2009 expressed an unqualified
opinion thereon.
/s/ ERNST & YOUNG LLP
Kansas City, Missouri
November 30, 2009
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,
2009, 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 2009 acquisitions, which are included in the 2009 consolidated
financial statements of Inergy, L.P. and Subsidiaries and constituted $14.4 million of total assets as of
September 30, 2009, and $10.5 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 its fiscal 2009 acquisitions.
In our opinion, Inergy, L.P. and Subsidiaries maintained, in all material respects, effective internal control over
financial reporting as of September 30, 2009, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the 2009 consolidated financial statements of Inergy, L.P. and Subsidiaries and our report dated
November 30, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Kansas City, Missouri
November 30, 2009
96
Inergy, L.P. and Subsidiaries
Consolidated Balance Sheets
(in millions, except unit information)
Assets
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, less allowance for doubtful accounts of $2.7 million and $6.4
million at September 30, 2009 and 2008, respectively . . . . . . . . . . . . . . . . . . . . . . . .
Inventories (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets from price risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30,
2009
2008
$
11.6
$
17.3
94.7
96.5
23.8
20.2
139.4
99.9
33.3
21.9
311.8
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
246.8
Property, plant and equipment (Note 4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,555.2
327.9
1,275.0
244.7
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,227.3
1,030.3
Intangible assets (Note 4):
Customer accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
277.4
133.0
410.4
133.1
277.3
374.3
7.4
266.7
127.0
393.7
105.5
288.2
443.0
4.0
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,133.1
$2,077.3
Liabilities and partners’ capital
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities from price risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term debt (Note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
71.7
74.1
60.1
29.3
22.0
$ 114.7
68.9
87.7
57.0
60.5
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
257.2
388.8
Long-term debt, less current portion (Note 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,071.3
0.9
4.3
1,046.1
1.0
3.6
Partners’ capital (deficit) (Note 9):
Common unitholders (59,807,087 units and 50,715,074 units issued and outstanding
as of September 30, 2009 and 2008, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-managing general partner and affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
800.0
(0.6)
799.4
637.6
0.2
637.8
Total liabilities and partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,133.1
$2,077.3
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 per unit data)
Year Ended September 30,
2009
2008
2007
Revenue:
Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,124.4 $1,386.8 $1,150.4
332.7
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
492.1
446.2
Cost of product sold (excluding depreciation and amortization as shown below):
Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
737.4
259.5
1,053.0
323.7
820.0
206.1
1,570.6
1,878.9
1,483.1
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expenses:
Operating and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense):
Interest expense, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes and interest of non-controlling partners in ASC . . . . . .
Provision for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated net income . . . . . . . . . . .
996.9
1,376.7
1,026.1
573.7
502.2
457.0
279.6
115.8
5.2
173.1
(69.7)
0.1
103.5
(0.7)
(1.4)
265.6
98.0
11.5
127.1
(60.9)
1.0
67.2
(0.7)
(1.4)
247.8
83.4
8.0
117.8
(52.0)
1.9
67.7
(0.7)
—
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 101.4 $
65.1 $
67.0
Partners’ interest information:
Non-managing general partner and affiliates interest in net income . . . . . $
Beneficial conversion value of Special Units (Note 9) . . . . . . . . . . . . . . . .
Distribution paid on restricted units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
47.0 $
—
0.8
36.1 $
—
0.3
Total interest in net income not attributable to limited partners’ . . . . . . . . . . . . $
47.8 $
36.4 $
27.5
10.3
0.2
38.0
Total limited partners’ interest in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . $
53.6 $
28.7 $
29.0
Net income per limited partner unit:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1.00 $
0.58 $
0.61
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1.00 $
0.57 $
0.61
Weighted average limited partners’ units outstanding (in thousands):
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dilutive units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,709
27
49,777
74
47,693
182
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53,736
49,851
47,875
The accompanying notes are an integral part of these consolidated financial statements.
98
Inergy, L.P. and Subsidiaries
Consolidated Statements of Partners’ Capital
(in millions)
Balance at September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net proceeds from issuance of common units . . . . . . . . . . . . . .
Net proceeds from common unit options exercised . . . . . . . . . .
Unit based compensation charges . . . . . . . . . . . . . . . . . . . . . . . .
Special Units converted to common units . . . . . . . . . . . . . . . . .
Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive income:
Common
Unit
Capital
$ 648.8
104.5
3.9
0.7
25.0
(108.4)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized fair value on cash flow hedges . . . .
39.5
25.5
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
739.5
Net proceeds from common unit options exercised . . . . . . . . . .
Issuance of common units for acquisition . . . . . . . . . . . . . . . . .
Unit based compensation charges . . . . . . . . . . . . . . . . . . . . . . . .
Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive income:
1.3
20.1
3.5
(121.6)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized fair value on cash flow hedges . . . .
29.0
(34.2)
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
637.6
Net proceeds from issuance of common units . . . . . . . . . . . . . .
Net proceeds from common unit options exercised . . . . . . . . . .
Issuance of common units for acquisition . . . . . . . . . . . . . . . . .
Unit based compensation charges . . . . . . . . . . . . . . . . . . . . . . . .
Retirement of common units . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive income:
201.2
0.8
6.7
3.1
(0.7)
(139.1)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized fair value on cash flow hedges . . . .
54.4
36.0
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-Managing
General
Partners and
Affiliate
$ 2.3
—
—
—
—
(28.4)
27.5
0.3
1.7
—
—
—
(37.3)
36.1
(0.3)
0.2
—
—
—
—
—
(48.1)
47.0
0.3
Special
Unit
Capital
$ 25.0
—
—
(25.0)
—
Total
Partners’
Capital
$ 676.1
104.5
3.9
0.7
—
(136.8)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
67.0
25.8
92.8
741.2
1.3
20.1
3.5
(158.9)
65.1
(34.5)
30.6
637.8
201.2
0.8
6.7
3.1
(0.7)
(187.2)
101.4
36.3
137.7
Balance at September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 800.0
$ (0.6)
$ — $ 799.4
The accompanying notes are an integral part of these consolidated financial statements.
99
Inergy, L.P. and Subsidiaries
Consolidated Statements of Cash Flows
(in millions)
Operating activities
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs and net bond discount
. . . . . . . . . . .
Unit-based compensation charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest of non-controlling partners in ASC’s consolidated net income . . . . . .
Provision for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets (liabilities) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net assets (liabilities) from price risk management activities . . . . . . . . . .
Year Ended September 30,
2009
2008
2007
$ 101.4
$ 65.1 $ 67.0
88.8
27.0
5.2
3.1
1.4
3.7
5.2
41.4
3.9
1.4
—
(44.7)
11.1
(27.5)
18.0
73.7
24.3
2.3
3.5
1.4
5.7
11.5
(18.2)
8.2
(1.1)
(1.0)
7.2
(6.7)
18.6
(10.7)
59.7
23.7
2.4
0.7
—
3.3
8.0
(19.2)
8.4
(5.3)
2.9
16.4
(1.7)
(17.9)
19.5
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
239.4
183.8
167.9
Investing activities
Acquisitions, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of property, plant and equipment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(12.1)
(224.8)
7.0
(0.7)
(215.1)
(200.1)
29.3
(0.8)
(99.6)
(100.9)
13.1
(0.4)
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(230.6)
(386.7)
(187.8)
The accompanying notes are an integral part of these consolidated financial statements.
100
Inergy, L.P. and Subsidiaries
Consolidated Statements of Cash Flows (continued)
(in millions)
Year Ended September 30,
2009
2008
2007
Financing activities
Proceeds from the issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Premium on issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Principal payments on long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payments for deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net proceeds from issuance of common units . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net proceeds from unit options exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions to minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 882.5
—
(905.6)
(187.2)
(5.5)
201.2
0.8
(0.7)
$1,028.2
4.0
(657.8)
(158.9)
(3.5)
—
1.3
(0.8)
$ 394.3
—
(350.3)
(136.8)
—
104.5
3.9
—
Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . .
(14.5)
212.5
15.6
Net increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(5.7)
17.3
9.6
7.7
(4.3)
12.0
Cash at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 11.6
$
17.3
$
7.7
Supplemental disclosure of cash flow information
Cash paid during the period for interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 65.8
$
63.6
$ 53.2
Supplemental schedule of noncash investing and financing activities
Additions to intangible assets through the issuance of noncompetition agreements
and notes to former owners of businesses acquired . . . . . . . . . . . . . . . . . . . . . . .
Net change to property, plant and equipment through accounts payable and
accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in the fair value of interest rate swap and related long-term debt
. . . . . . .
Acquisitions, net of cash acquired:
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill (Note 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
4.3
$
5.3
$
5.5
(6.2) $
11.3 $
$
$
$
$
3.7
0.7
79.4
8.7
(68.8)
—
(1.2)
(6.7)
—
4.5
21.1
111.8
28.1
95.8
0.7
(6.0)
(20.1)
(16.3)
0.5
1.1
0.4
76.5
13.4
14.9
—
(5.6)
—
—
Total acquisitions, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 12.1
$ 215.1
$ 99.6
The accompanying notes are an integral part of these consolidated financial statements.
101
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements
Note 1. Partnership Organization and Formation
Organization
The consolidated financial statements of Inergy, L.P. (“Inergy”, “The Partnership” or the “Company”) include
the accounts of Inergy and its subsidiaries, including Inergy Propane, LLC (“Inergy Propane”), Inergy
Midstream, LLC (collectively, the “Operating Companies”) and Inergy Finance Corp.
Inergy Partners, LLC (“Inergy Partners” or the “Non-Managing General Partner”), a subsidiary of Inergy
Holdings, L.P. (“Holdings”), owns the Non-Managing General Partner interest in the Company. Inergy GP, LLC
(“Inergy GP” or the “Managing General Partner”), a wholly-owned subsidiary of Holdings, has sole
responsibility for conducting the Company’s business and managing its operations. Holdings is a holding
company whose principal business, through its subsidiaries, is its management of and ownership in the Company.
Holdings also directly owns the incentive distribution rights (“IDR”) with respect to Inergy.
Pursuant to a partnership agreement, Inergy GP or any of its affiliates is entitled to reimbursement for all direct
and indirect expenses incurred or payments made on behalf of Inergy and all other necessary or appropriate
expenses allocable to Inergy or otherwise reasonably incurred by Inergy GP in connection with operating the
Company’s business. These costs, which totaled $3.1 million for the fiscal year ended September 30, 2009, and
$3.5 million for each of the fiscal years ended September 30, 2008 and 2007, include compensation, bonuses and
benefits paid to officers and employees of Inergy GP and its affiliates.
As of September 30, 2009, Holdings owns an aggregate 8.6% interest in Inergy, L.P., inclusive of ownership of
all of the non-managing general partner and the managing general partner. This ownership is comprised of a
0.8% general partnership interest and 7.8% limited partnership interest.
Nature of Operations
Inergy is engaged primarily in the sale, distribution, storage, marketing, trading, processing and fractionation of
propane, natural gas and other natural gas liquids. The retail market is seasonal because propane is used primarily
for heating in residential and commercial buildings, as well as for agricultural purposes. Inergy’s operations are
primarily concentrated in the Midwest, Northeast and South regions of the United States.
Principles of Consolidation
All significant intercompany balances and transactions have been eliminated in consolidation.
Reclassifications
The consolidated balance sheet for the year ended September 30, 2008 reflects an increase to both accounts
receivable and accounts payable of $9.8 million. Certain other prior period amounts have been reclassified to
conform to the current period presentation. These reclassifications had no effect on net income.
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
102
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
exposure to interest rate risk associated with fixed 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 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. These 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. Any ineffective portion of the fair value hedges is recognized as cost of product sold in
the current period. Inergy recognized a $0.2 million net gain in the year ended September 30, 2009, related to the
ineffective portion of its fair value hedging instruments. In addition, for the year ended September 30, 2009,
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. 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. Any ineffective portion of the gain or loss is recognized as cost of product
sold in the current period. Accumulated other comprehensive income (loss) was $11.0 million and $(25.3)
million at September 30, 2009 and 2008, respectively. Approximately $11.7 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 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 later of the time of sale or
installation. Revenue from repairs and maintenance is recognized upon completion of the service. Revenue from
storage contracts is recognized during the period in which storage services are provided.
Expense Classification
Cost of product sold consists of tangible products sold including all propane and other natural gas liquids, salt
and all propane related appliances. 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 $134.6
million, $131.0 million and $114.7 million during the years ended September 30, 2009, 2008 and 2007,
respectively.
103
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Credit Risk and Concentrations
Inergy is both a retail and wholesale supplier of propane gas. Inergy generally extends unsecured credit to its
wholesale customers in the United States and Canada. In addition, Inergy collects margin payments from its
customers to mitigate risk. Credit is generally extended to retail customers through delivery into Company and
customer owned propane gas storage tanks. Provisions for doubtful accounts receivable are based on specific
identification and historical collection results and have generally been within management’s expectations.
Inergy enters into netting agreements with certain wholesale customers to mitigate the Company’s credit risk.
Realized gains and losses reflected in the Company’s receivables and payables are reflected at 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, BP Amoco Corp. (12%) and Sunoco, Inc. (11%), accounted for 23% of propane purchases during
the past fiscal year. The Company believes that contracts with these suppliers will enable Inergy to purchase
most of its supply needs at market prices and ensure adequate supply. No other single supplier accounted for
more than 10% of propane purchases in the current year.
No single customer represents 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 retail 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. Wholesale propane and other liquids 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, 2009 and 2008, amount to $53.7
million and $36.4 million, respectively. Inventories for midstream 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.”
104
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Property, Plant and Equipment
Property, plant and equipment are stated at cost. Depreciation is computed by the straight-line method over the
estimated useful lives of the assets, as follows:
Buildings and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tanks and plant equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years
25 – 40
3 – 10
5 – 10
5 – 30
Salt deposits are depleted on a unit of production method.
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 determined that
no impairment exists as of September 30, 2009. See Note 4 for a discussion of assets held for sale at
September 30, 2009 and 2008.
Identifiable Intangible Assets
The Company has recorded certain identifiable intangible assets, including customer accounts, covenants not to
compete, trademarks, deferred financing costs and deferred acquisition costs. Customer accounts, covenants not
to compete and trademarks have arisen from the various acquisitions by Inergy. Deferred financing costs
represent financing costs incurred in obtaining financing and are being amortized over the term of the related
debt. Deferred acquisition costs represent costs incurred on acquisitions that Inergy is actively pursuing.
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:
Customer accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Covenants not to compete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years
15
2 – 10
1 – 10
Trademarks have been assigned an indefinite economic life and are not being amortized, but are subject to an
annual impairment evaluation.
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,
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$30.0
27.5
25.8
25.6
25.4
105
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Goodwill
Goodwill is recognized for various acquisitions by Inergy 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, 2009.
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 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 remaining Inergy subsidiaries generate at
least 90% of gross income from qualifying sources. As a result, except for the operations of Services, Inergy’s
net earnings for Federal income tax purposes are allocated to the individual partners for inclusion in their tax
returns. Legislation in certain states allows for taxation of partnerships. As such, certain state taxes for Inergy
have also been included in the accompanying financial statements as income taxes due to the nature of the tax in
those particular states. 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.
The provision for income tax was $0.7 million for the years ended September 30, 2009, 2008 and 2007. At
September 30, 2009, the Company had cumulative temporary differences between the book and tax basis of
Services of $17.2 million, comprised primarily of a net operating loss carryforward. At September 30, 2009 and
2008, this resulted in a deferred tax asset of $6.5 million and $5.9 million, respectively, which the Company has
fully reserved with a valuation allowance of $6.5 million and $5.9 million, respectively. In order to fully realize
the deferred tax asset Services will need to generate future taxable income. A valuation allowance is provided
when it is more likely than not that some or all of the deferred tax asset will not be realized. Based on the level of
current taxable income and projections of future taxable income of Services over the periods in which the
deferred tax asset would be deductible, the Company is providing a full valuation allowance that it is more likely
than not that that it will not realize the full benefit of the deferred tax asset.
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.
106
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Customer Deposits
Customer deposits primarily represent cash received by Inergy from wholesale and retail customers for propane
purchased under contract that will be delivered at a future date.
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 reserve for bad debts) and payables are carried at cost,
which approximates fair value due to their liquid and short-term nature. As of September 30, 2009, the estimated
fair value of the fixed-rate Senior Notes, based on available trading information, totaled $1,041.3 million
compared with the aggregate principal amount at maturity of $1,050.0 million. The Company’s credit agreement
(“Credit Agreement”) consists of a $75 million revolving working capital facility (“Working Capital Facility”)
and a $350 million revolving acquisition facility (“Acquisition Facility”). The carrying value of amounts
outstanding under the Credit Agreement of $27.2 million at September 30, 2009, approximate fair value due
primarily to the floating interest rate associated with the Credit Agreement.
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):
As of September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive income(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive income(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated
Other
Comprehensive
Income (Loss)
$ 9.2
(34.5)
(25.3)
36.3
$ 11.0
(a) Other comprehensive income (loss) includes a reclassification of $(24.5) million and $9.8 million to net income during the years ended
September 30, 2009 and 2008, 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.
107
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Income Per Unit
The Company calculates basic net income per unit by dividing net income, after considering the Non-Managing
General Partner’s interest, including priority distributions and beneficial conversion value (Note 9), by the
weighted average number of limited partner units outstanding. Under this method, the calculation of net income
per unit reflects an allocation of earnings to each class of units that is consistent with the partnership agreement’s
treatment of the respective classes’ capital accounts. Diluted net income per limited partner unit is computed by
dividing net income, after considering the Non-Managing General Partner’s interest, by the sum of weighted
average number of common units and the effect of other dilutive units.
Accounting for Unit-Based Compensation
Inergy has a unit-based employee compensation plan and all share-based payments to employees, including
grants of employee stock options, are recognized in the income statement based on their fair values.
The amount of compensation expense recorded by the Company during the years ended September 30, 2009,
2008 and 2007, was $3.1 million, $3.5 million and $0.7 million, respectively. The compensation expense for the
years ended September 30, 2009, 2008 and 2007, includes $1.4 million, $1.1 million and $0.3 million,
respectively, of unit-based compensation expense on Inergy Holdings, L.P. units.
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 assessing 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 13
for disclosures related to Inergy’s propane and midstream segments.
Recently Issued Accounting Pronouncements
FASB Accounting Standards Codification Subtopic 825-10 (“825-10”), originally issued as SFAS No. 159, “The
Fair Value Option for Financial Assets and Financial Liabilities”, was issued in February 2007 to permit entities
to choose to measure many financial instruments and certain other items at fair value at specified election dates.
A business entity is required to report unrealized gains and losses on items for which the fair value option has
been elected in earnings at each subsequent reporting date. The Company adopted 825-10 on October 1, 2008.
The adoption of 825-10 did not have an impact the Company’s financial statements.
FASB Accounting Standards Codification Subtopic 820-10 (“820-10”), originally issued as SFAS No. 157, “Fair
Value Measurements”, was issued in September 2006 to define fair value, establish a framework for measuring
fair value according to generally accepted accounting principles and expand disclosures about fair value
measurements. The Company adopted 820-10 on October 1, 2008. The adoption of 820-10 required certain
additional footnote disclosures (Note 6), however, it did not have a significant impact on any amounts comprising
the consolidated balance sheets, consolidated statements of operations, consolidated statements of partners’
capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 210-20 (“210-20”), originally issued as FASB Staff Position
No. FIN 39-1, “Amendment of FASB Interpretation No. 39”, was issued in April 2007 to permit companies to
108
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
offset fair value amounts recognized for the right to reclaim cash collateral (a receivable), or the obligation to
return cash collateral (a payable), against fair value amounts recognized for derivative instruments executed with
the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted
to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments
under master netting arrangements. The Company adopted 210-20 on October 1, 2008 and elected to change its
accounting policy for derivative instruments executed with the same counterparty under a master netting
agreement. The Company’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. This change in accounting
policy has been presented retroactively. The adoption of 210-20 had the following impact on the September 30,
2008 consolidated balance sheet (in millions):
Assets from price risk management activities . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities from price risk management activities . . . . . . . . . . . . . . . . .
$79.2
46.1
89.5
96.5
97.7
$(45.9)
(24.2)
(20.6)
(8.8)
(40.7)
$33.3
21.9
68.9
87.7
57.0
Original Value Adjustment Adjusted Value
FASB Accounting Standards Codification Subtopic 815-10 (“815-10”), originally issued as SFAS No. 161,
“Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133”
was issued in March 2008 and applies to all derivative instruments and related hedged items. 815-10 requires
entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, results of operations and cash flows. The Company adopted
815-10 on March 31, 2009. The adoption of 815-10 required certain additional disclosures (Note 5), however, it
did not impact any amounts comprising the consolidated balance sheets, consolidated statements of operations,
consolidated statements of partners’ capital or the consolidated statements of cash flows.
FASB Accounting Standards Codification Subtopic 805-10 (“805-10”), originally issued as SFAS No. 141
(revised 2007), “Business Combinations”, was issued in December 2007 and establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. 805-10
also establishes disclosure requirements designed to enable users to evaluate the nature and financial effects of
the business combination. 805-10 is required to be adopted by the Company for business combinations for which
the acquisition date is on or after October 1, 2009.
FASB Accounting Standards Codification Subtopic 810-10 (“810-10”), originally issued as SFAS No. 160,
“Non-controlling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”, was issued in
December 2007 and requires that accounting and reporting for minority interests will be recharacterized as
non-controlling interests and classified as a component of equity. 810-10 also establishes reporting requirements
that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the
interests of the non-controlling owners. 810-10 applies to all entities that prepare consolidated financial
statements, except not-for-profit organizations, but will affect only those entities that have an outstanding
non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. 810-10 is required to be
adopted by the Company for the fiscal quarter ended December 31, 2009. The Company is evaluating the
potential financial statement impact of 810-10 to its consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as EITF Issue No. 07-4,
“Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships”, was
109
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
ratified in March 2008 and applies to Master Limited Partnerships (“MLP”) that are required to make incentive
distributions when certain thresholds have been met regardless of whether the IDR is a separate limited partner
(“LP”) interest or embedded in the general partner interest. 260-10 addresses how the current period earnings of
an MLP should be allocated to the general partner, LP’s and, when applicable, IDR’s. 260-10 is required to be
adopted by the Company for the fiscal quarter ended December 31, 2009. The Company evaluating the potential
financial statement impact of 260-10 to its consolidated financial statements.
FASB Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as FSP EITF Issue
No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating
Securities”, was ratified in June 2008 and applies to the calculation of earnings per share (“EPS”) under FASB
Accounting Standards Codification Subtopic 260-10 (“260-10”), originally issued as SFAS 128, “Earnings Per
Share”, for share-based payment awards with rights to dividends or dividend equivalents. 260-10 states that
unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are
participating securities and shall be included in the computation of EPS pursuant to the two-class method. 260-10
is required to be adopted by the Company for the fiscal quarter ended December 31, 2009. The Company is
evaluating the potential financial statement impact of 260-10 to its consolidated financial statements.
In May 2009, the FASB issued FASB Accounting Standards Codification Subtopic 855-10 (“855-10”), originally
issued as SFAS No. 165, “Subsequent Events”. 855-10 establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before financial statements are issued or are
available to be issued. The Company adopted 855-10 on June 30, 2009. The adoption of 855-10 required the
Company to disclose the date through which subsequent events have been evaluated and the basis for that date
(Note 15). The adoption of 855-10 did not impact any amounts comprising the consolidated balance sheets,
consolidated statements of operations, consolidated statements of partners’ capital or the consolidated statements
of cash flows.
In June 2009, the FASB issued FASB Accounting Standards Codification Subtopic 105-10 (“105-10”), originally
issued as SFAS 168, “The FASB Accounting Standards Codification and Hierarchy of Generally Accepted
Accounting Principles”, to supersede FASB Statement No. 162, “The Hierarchy of Generally Accepted
Accounting Principles”, and reorganize the standards applicable to financial statements of nongovernmental
entities that are presented in conformity with GAAP. The purpose of the codification was to provide a single
source of authoritative nongovernmental GAAP literature. The codification was not intended to create new
accounting standards or guidance. While the codification includes portions of SEC content related to matters
within the basic financial statements for user convenience, it does not contain all SEC guidance on accounting
topics, and does not replace any SEC rules or regulations. The Company adopted 105-10 on September 30, 2009.
The adoption of 105-10 did not impact any amounts comprising the consolidated balance sheets, consolidated
statements of operations, consolidated statements of partners’ capital or the consolidated statements of cash
flows.
Note 3. Acquisitions
During the fiscal year ended September 30, 2009, Inergy made three retail acquisitions, including the Blu-Gas
group of companies (“Blu-Gas”), Newton’s Gas Service, Inc. (“Newton’s Gas”) and F.G. White Company, Inc.
(“F.G. White”). The aggregate purchase price of these acquisitions, net of cash acquired, was $11.8 million. This
amount does not include $0.3 million paid in fiscal 2009 for acquisitions that closed in the previous year. The
purchase price allocation for these acquisitions has been prepared on a preliminary basis pending final asset
valuation and asset rationalization, and changes are expected when additional information becomes available.
The Company finalized its purchase price allocation of the 2008 US Salt acquisition during 2009. This allocation
resulted in an increase to property, plant and equipment of $69.4 million and an increase to intangible assets of
110
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
$3.6 million, with a corresponding decrease to goodwill of $73.0 million. Other purchase accounting adjustments
recorded in fiscal 2009 resulted in a net increase to goodwill of $4.3 million. Changes to reflect final asset
valuation of other prior fiscal year acquisitions have been included in the Company’s consolidated financial
statements but are not material.
U.S. GAAP requires that for any material business combination or disposition of assets, pro-forma information
must be disclosed. The fiscal 2009 acquisitions were not considered material.
The operating results for these acquisitions are included in the consolidated results of operations from the dates
of acquisition through September 30, 2009.
As a result of the fiscal 2009 acquisitions, the Company acquired $0.7 million of goodwill and $9.5 million of
intangible assets, consisting of the following (in millions):
Customer accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncompetition agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$6.8
2.7
$9.5
The amounts provided above relate solely to acquisitions that closed in fiscal 2009. The amounts disclosed in the
supplemental schedule of noncash investing and financing activities in the consolidated statement of cash flows
relate to amounts recorded during 2009, which related to acquisitions that closed in fiscal 2009 and 2008.
The weighted average amortization period of amortizable intangible assets acquired during the year ended
September 30, 2009, is approximately thirteen years.
Note 4. Certain Balance Sheet Information
Inventories
Inventories consist of the following at September 30, 2009 and 2008, respectively (in millions):
Propane gas and other liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Appliances, parts and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Salt finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30,
2009
2008
$81.3
14.8
0.4
$96.5
$83.9
15.3
0.7
$99.9
111
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Property, Plant and Equipment
Property, plant and equipment consists of the following at September 30, 2009 and 2008, respectively
(in millions):
Tanks and plant equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Buildings and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction in process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Salt deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Office furniture and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . .
Total property, plant and equipment, net
September 30,
2009
2008
$ 916.7
323.6
107.7
136.0
41.6
29.6
1,555.2
327.9
$1,227.3
$ 713.8
265.6
104.5
166.5
—
24.6
1,275.0
244.7
$1,030.3
Depreciation expense totaled $88.6 million, $73.7 million and $59.7 million for the years ended September 30,
2009, 2008 and 2007, respectively. Depletion expense totaled $0.2 million for the year ended September 30, 2009.
The tanks and plant equipment balances above include tanks owned by the Company that reside at customer
locations. The leases associated with these tanks are accounted for as operating leases. These tanks have a value
of $424.0 million with an associated accumulated depreciation balance of $89.3 million at September 30, 2009.
At September 30, 2009 and 2008, the Company capitalized interest of $14.8 million and $5.5 million,
respectively, related to certain midstream asset expansion projects.
The property, plant and equipment balances above at September 30, 2009 and 2008, include $2.0 million and
$4.5 million, respectively, of propane operations assets deemed held for sale. These assets were identified
primarily as a result of losses due to disconnecting customer installations of unprofitable accounts due to low
margins, poor payment history or low volume usage. As a result, the carrying value of these assets was reduced
to their estimated recoverable value less anticipated disposition costs, resulting in losses of $4.9 million and
$11.5 million for the years ended September 30, 2009 and 2008, respectively. The $4.9 million and $11.5 million
charges are included as components of operating income as losses on disposal of assets. When aggregated with
other realized losses, such amounts totaled $5.2 million and $11.5 million, respectively.
Intangible Assets
Intangible assets consist of the following at September 30, 2009 and 2008, respectively (in millions):
Customer accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(accumulated amortization—customer accounts) . . . . . . . . . . . . . . . . . . .
Covenants not to compete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(accumulated amortization—covenants not to compete) . . . . . . . . . . . . .
Deferred financing and other costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(accumulated amortization—deferred financing costs)
. . . . . . . . . . . . . .
Trademarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30,
2009
2008
$277.4
(82.6)
72.5
(35.5)
34.3
(15.0)
26.2
$266.7
(64.8)
72.2
(29.9)
28.5
(10.8)
26.3
Total intangible assets, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$277.3
$288.2
112
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Amortization and interest expense associated with the above described intangible assets at September 30, 2009,
2008 and 2007, amounted to $30.3 million, $26.8 million and $26.1 million, respectively.
Note 5. 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 utilizes derivative instruments to manage its exposure to fluctuations in interest rates, which
is discussed more fully in Note 7. Additional information related to derivatives is provided in Note 2 and Note 6.
Commodity Derivative Instruments and Price Risk Management
Risk Management Activities
Inergy sells propane and other commodities 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 hedge against the exposure its customer contracts create. Inergy does not designate these
instruments as hedging instruments. 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. However, immaterial net unbalanced positions can
exist or are established based on assessment of anticipated short-term needs or market conditions.
Cash Flow Hedging Activity
Inergy sells propane and heating oil to retail customers at fixed prices. Inergy will enter into derivative
instruments to hedge a significant portion of its exposure to fluctuations in commodity prices as a result of selling
the fixed price contracts. These instruments are identified and qualify to be treated as cash flow hedges. This
accounting treatment requires the effective portion of the gain or loss on the derivative to be reported as a
component of other comprehensive income and reclassified into earnings in the same period or periods during
which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge
ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current
earnings.
Fair Value Hedging Activity
Inergy will enter into derivative instruments to hedge its exposure to fluctuating commodity prices that results
from maintaining its wholesale propane and other liquids inventory. Those instruments 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.
Commodity inventory held in bulk storage facilities is not expected to be sold in the immediate future and is
hedged in order to minimize exposure to fluctuations in commodity prices. Commodity inventory held at retail
locations is not hedged as this inventory is expected to be sold in the immediate future and is therefore not
exposed to fluctuations in commodity prices over an extended period of time.
113
Inergy, L.P. and Subsidiaries
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 include the following at
September 30, 2009, and September 30, 2008 (in millions):
September 30, 2009
September 30, 2008
Fixed Price
Payor
Fixed Price
Receiver
Fixed Price
Payor
Fixed Price
Receiver
Propane, crude and heating oil (barrels) . . . . . . . .
Natural gas (MMBTU’s) . . . . . . . . . . . . . . . . . . . .
6.8
—
6.5
—
8.9
0.7
7.5
—
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, 2009
Derivatives in fair value hedging relationships:
Commodity(a)
Debt(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total fair value of derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(12.3)
3.7
$ (8.6)
Amount of Gain
(Loss) Recognized in
OCI on Effective
Portion of
Derivatives
Amount of Gain
(Loss) Reclassified
from OCI to Net
Income
Year Ended
September 30, 2009
$12.5
(3.7)
$ 8.8
Amount of Gain
(Loss) Recognized in
Net Income on
Ineffective Portion
of Derivatives &
Amount Excluded
from Testing
Derivatives in cash flow hedging relationships:
Commodity(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$11.8
$(24.5)
$—
Amount of Gain
(Loss) Recognized in
Net Income from
Derivatives
Year Ended
September 30, 2009
Derivatives not designated as hedging instruments:
Commodity(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$15.0
(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.
114
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
(b)
(c)
(d)
The gain (loss) on both the derivative and the item being hedged are located in interest expense in the consolidated statements of
operations.
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.
The gain (loss) is recognized in cost of product sold.
The following table summarizes the change in the unrealized fair value of energy derivative contracts related to
risk management activities for the years ended September 30, 2009 and 2008, where settlement has not yet
occurred (in millions):
Year Ended
September 30,
2009
2008
Net fair value gain (loss) of contracts outstanding at beginning of period . . . . . . . . . . . . . . . . . .
Net change in physical exchange contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net changes in cash paid against outstanding positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in fair value of contracts attributable to market movement during the period . . . . . . . . .
Realized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(23.7) $ 0.7
(0.1)
(0.5)
(9.9)
(13.9)
1.8
(10.1)
8.9
17.6
Net fair value of contracts outstanding at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (5.5) $(23.7)
All contracts subject to price risk had a maturity of twenty-one months or less, however, the majority of 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, 2009 and
2008, were propane retailers, resellers, energy marketers 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,
2009, is $17.3 million for which the Company has posted collateral of $5.4 million in the normal course of
business. The Company has received collateral of $9.6 million in the normal course of business on contracts with
a gross value of $60.6 million. All collateral amounts have been netted against the asset or liability with the
respective counterparty.
Note 6. 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
115
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
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.
As of September 30, 2009, 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 propane, heating oil,
crude oil, natural gas, natural gas liquids 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 an internal option model. The inputs utilized in the model are
based on publicly available information as well as broker quotes. These options have been categorized as level 3.
116
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
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 as of September 30, 2009 (in millions). 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.
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
Inventory . . . . . . . . . . . . . . . . . —
Interest rate swap . . . . . . . . . . . —
$ 58.5
$ 0.9
53.7 —
5.6 —
$ 60.6
53.7
5.6
Total assets at fair value . . . . .
$ 1.2
$117.8
$ 0.9
$119.9
$12.8
—
5.6
$18.4
$47.8
—
—
$47.8
$(36.8)
—
—
$(36.8)
$23.8
53.7
5.6
$83.1
Liabilities
Liabilities from price risk
management . . . . . . . . . . . . .
$ 5.7
$ 44.0
$ 1.1
$ 50.8
$ 8.1
$42.7
$(21.5)
$29.3
(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.
For assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level
3) during the period, 820-10 requires a reconciliation of the beginning and ending balances, separated for each
major category of assets. The reconciliation is as follows (in millions):
Fair Value
Measurements Using
Significant
Unobservable Inputs
(Level 3)
Year Ended
September 30, 2009
Beginning balance of OTC options . . . . . . . . . . . . . . . . . . . . .
Beginning balance recognized during the period . . . . . . . . . . .
Change in value of contracts executed during the period . . . . .
Ending balance of OTC options . . . . . . . . . . . . . . . . . . . . . . . .
$ 1.8
(1.8)
(0.2)
$(0.2)
117
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Note 7. Long-Term Debt
Long-term debt consisted of the following at September 30, 2009 and 2008, respectively (in millions):
Credit agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior unsecured notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value hedge adjustment on senior unsecured notes . . . . . . . . . . .
Bond premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bond discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ASC credit agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Obligations under noncompetition agreements and notes to former
owners of businesses acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30,
2009
2008
$
27.2
1,050.0
5.6
3.3
(19.7)
8.3
18.6
1,093.3
22.0
$ 247.0
825.0
1.9
3.8
—
10.9
18.0
1,106.6
60.5
Total long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,071.3
$1,046.1
Credit Agreement
The Company’s Credit Agreement consists of a $75 million revolving Working Capital Facility and a $350
million revolving Acquisition Facility. The effective amount of working capital borrowing capacity available to
the Company under the two facilities is $200 million utilizing capacity under the acquisition credit facility for
working capital needed during the winter heating season. The Credit Agreement is guaranteed by each of
Inergy’s wholly-owned domestic subsidiaries. The Company’s obligations under this Credit Agreement are
secured by liens and mortgages on the Company’s real and personal property. This Credit Agreement matures on
November 10, 2010.
Inergy is required to reduce the principal outstanding on the Working Capital Facility to $10 million or less for a
minimum of 30 consecutive days during the period commencing March 1 and ending September 30. As such,
$10 million of the outstanding balance at September 30, 2009 and 2008, have been classified as a long-term
liability in the accompanying consolidated balance sheets. At September 30, 2009, the balance outstanding under
the Credit Agreement was $27.2 million, with the entire balance borrowed for working capital purposes. At
September 30, 2008, the balance outstanding under the Credit Agreement was $247.0 million, including $182.0
million borrowed for acquisitions and growth capital expenditures and $65.0 million borrowed for working
capital purposes. Lehman Commercial Paper, Inc. (“Lehman CP”), a subsidiary of Lehman Brothers Holdings,
Inc., holds a $25 million lender commitment within Inergy’s Credit Agreement and filed for Chapter 11
Bankruptcy on October 5, 2008. Inergy does not plan for the Lehman lender commitment to be available for the
remainder of the term of the Credit Agreement. The interest rates of these revolvers are based on prime rate and
LIBOR plus the applicable spreads, which were between 2.0% and 3.5% at September 30, 2009, and between
4.24% and 5.46% at September 30, 2008, for all outstanding debt under the Credit Agreement. Unused
borrowings under the Credit Agreement amounted to $381.1 million and $154.4 million at September 30, 2009
and 2008, respectively. Outstanding standby letters of credit under the Credit Agreement amounted to $16.7
million and $23.6 million at September 30, 2009 and 2008, respectively.
As discussed in Note 15, the Company now has a $450 million general partnership revolving credit facility for
acquisitions, capital expenditures and general partnership purposes and a $75 million revolving working capital
facility.
At September 30, 2009, the Company was in compliance with all of its debt covenants.
118
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Senior Unsecured Notes
2014 Senior Notes
On December 22, 2004, Inergy and its wholly-owned subsidiary, Inergy Finance Corp (“Finance Corp.” and
together with Inergy, the “Issuers”) completed a private placement of $425 million in aggregate principal amount
of 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”). The 2014 Senior Notes contain covenants
similar to the Credit Agreement. The net proceeds were used to repay outstanding indebtedness.
The 2014 Senior Notes represent senior unsecured obligations and rank pari passu in right of payment with all
the Company’s other present and future senior indebtedness. The 2014 Senior Notes are fully, unconditionally,
jointly and severally guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has
no independent assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly,
condensed consolidating financial information for the parent and subsidiaries is not presented.
On October 26, 2005, Inergy completed an offer to exchange the 2014 Senior Notes for $425 million of 6.875%
senior notes due 2014 (the “2014 Exchange Notes”) that are registered and do not carry transfer restrictions,
registration rights and provisions for additional interest. The 2014 Exchange Notes did not provide Inergy with
any additional proceeds and satisfied its obligations under the registration rights agreement.
The 2014 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after
December 15, 2009, in each case at the redemption prices described in the table below, together with any accrued
and unpaid interest to the date of the redemption.
Year
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
103.438%
102.292%
101.146%
100.000%
Interest Rate Swaps
Inergy is party to six interest rate swap agreements scheduled to mature in December 2014, each designed to
hedge $25 million in underlying fixed rate senior unsecured notes in order to manage interest rate risk exposure.
These swap agreements, which expire on the same date as the maturity date of the related senior unsecured notes
due 2014 and contain call provisions consistent with the underlying senior unsecured notes, require the
counterparty to pay the Company an amount based on the stated fixed interest rate due every six months. In
exchange, Inergy is 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 6-month LIBOR interest rate plus spreads between
0.92% and 2.20% applied to the same notional amount of $150 million. The swap agreements have been
accounted for as fair value hedges. Amounts to be received or paid under the agreements are accrued and
recognized over the life of the agreements as an adjustment to interest expense. The change in the market value
of the interest rate swaps for the year ended September 30, 2009, was recorded as a $3.7 million decrease to
interest expense. This amount was offset by a $3.7 million increase to interest expense that was recorded as a
result of a change in the fair value of the hedged fixed rate debt.
2016 Senior Notes
On January 11, 2006, Inergy and its wholly-owned subsidiary, Inergy Finance Corp. issued $200 million
aggregate principal amount of 8.25% senior unsecured notes due 2016 (“2016 Senior Notes”) in a private
placement to eligible purchasers.
119
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
The 2016 Senior Notes contain covenants similar to the 2014 Senior Notes. Inergy used the net proceeds of the
offering to repay outstanding indebtedness under the revolving acquisition credit facility. The 2016 Senior Notes
represent senior unsecured obligations of Inergy and rank pari passu in right of payment with all other present
and future senior indebtedness of Inergy. The 2016 Senior Notes are fully, unconditionally, jointly and severally
guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has no independent
assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly, condensed
consolidating financial information for the parent and subsidiaries is not presented.
On May 18, 2006, Inergy completed an offer to exchange its existing 8.25% 2016 Senior Notes for $200 million
of 8.25% senior notes due 2016 (the “2016 Exchange Notes”) that are registered and do not carry transfer
restrictions, registration rights and provisions for additional interest. The 2016 Exchange Notes did not provide
Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.
The 2016 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after March 1,
2011, in each case at the redemption prices described in the table below, together with any accrued and unpaid
interest to the date of the redemption.
Year
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
104.125%
102.750%
101.375%
100.000%
In April 2008, Inergy issued an additional $200 million of senior unsecured notes as an add-on to its existing
8.25% Senior Unsecured Notes due 2016 under Rule 144A to eligible purchasers. The notes mature on March 1,
2016. The proceeds from the bond issuance were $204 million, representing a 2% premium to par value. On
September 16, 2008, Inergy completed an offer to exchange the additional $200 million of 8.25% senior notes
due 2016 for $200 million of 8.25% senior notes due 2016 (the “Additional 2016 Exchange Notes”) that are
registered and do not carry transfer restrictions, registration rights and provisions for additional interest. The
Additional 2016 Exchange Notes did not provide Inergy with any additional proceeds and satisfied its obligations
under the registration rights agreement.
2015 Senior Notes
On February 2, 2009, Inergy and its wholly-owned subsidiary, Inergy Finance Corp, issued $225 million
aggregate principal amount of 8.75% senior unsecured notes due 2015 (the “2015 Senior Notes”) under Rule
144A to eligible purchasers. The 8.75% notes mature on March 1, 2015, and were issued at 90.191% of the
principle amount to yield 11%.
The 2015 Senior Notes contain covenants similar to the 2014 and 2016 Senior Notes. Inergy used the net
proceeds of the offering to repay outstanding indebtedness under the revolving acquisition credit facility. The
2015 Senior Notes represent senior unsecured obligations of Inergy and rank pari passu in right of payment with
all other present and future senior indebtedness of Inergy. The 2015 Senior Notes are fully, unconditionally,
jointly and severally guaranteed by all of Inergy’s wholly-owned current domestic subsidiaries. Also, Inergy has
no independent assets or operations, and subsidiaries not guaranteeing the indenture are minor. Accordingly,
condensed consolidating financial information for the parent and subsidiaries is not presented.
On October 7, 2009, Inergy completed an offer to exchange its existing 8.75% 2015 Senior Notes for $225
million of 8.75% senior notes due 2015 (the “2015 Exchange Notes”) that are registered and do not carry transfer
120
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
restrictions, registration rights and provisions for additional interest. The 2015 Exchange Notes did not provide
Inergy with any additional proceeds and satisfied Inergy’s obligations under the registration rights agreement.
The 2015 Senior Notes are redeemable, at Inergy’s option, in whole or in part, at any time on or after March 1,
2013, in each case at the redemption prices described in the table below, together with any accrued and unpaid
interest to the date of the redemption.
Year
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Percentage
104.375%
100.000%
ASC Credit Agreement
Steuben Gas Storage Company, a majority-owned subsidiary of Arlington Storage Company (“ASC”) had a debt
agreement in place at the time of the Company’s acquisition of ASC (“ASC Credit Agreement”). The ASC
Credit Agreement is secured by the assets of Steuben and has no recourse against the assets of the Company. The
ASC Credit Agreement is scheduled to mature in December 2015. The interest rate on half of the ASC Credit
Agreement is at a fixed rate, while the other half is based on LIBOR plus the applicable spreads.
Notes Payable and Other Obligations
Non-interest bearing obligations due under noncompetition agreements and other note payable agreements
consist of agreements between Inergy and the sellers of retail propane companies acquired from fiscal years 2003
through 2009 with payments due through 2019 and imputed interest ranging from 8.0% to 9.0%. Noninterest-
bearing obligations consist of $24.4 million and $22.4 million in total payments due under agreements, less
unamortized discount based on imputed interest of $5.8 million and $4.4 million at September 30, 2009 and
2008, 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):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
22.0
14.6
4.0
3.5
3.2
1,046.0
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,093.3
Long-Term Debt
and Notes Payable
Note 8. Leases
Inergy has certain noncancelable operating leases, mainly for office space and vehicles, 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.
121
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
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,
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10.1
7.7
6.3
4.9
3.6
6.2
$38.8
Rent expense for operating leases for the years ending September 30, 2009, 2008 and 2007, totaled $11.7 million,
$10.6 million and $9.7 million, respectively.
Inergy has certain related party leases as discussed in Note 12.
Note 9. Partners’ Capital
Special Units
In August 2005, Inergy issued for aggregate gross proceeds of $25 million, 769,941 special units (the “Special
Units”), representing a new class of equity securities in Inergy that were not entitled to a current cash distribution
but would convert into common units representing limited partnership interests in Inergy at a specified
conversion rate upon the commercial operation of the Stagecoach expansion project. The Special Units were
issued to fund the $25 million acquisition of the rights to the Phase II expansion project of the Stagecoach natural
gas storage facility in connection with the Stagecoach acquisition and were issued to Holdings.
On April 25, 2007, the 769,941 Special Units converted into 919,349 common units as a result of the commercial
operation of the Phase II expansion of the Stagecoach natural gas storage facility. This beneficial conversion
feature present in these Special Units was valued at $10.3 million and has been recognized as a non-cash
allocation of (income) to the holder of the converted units for the purpose of calculating earnings per limited
partner unit.
Common Unit Offerings
On March 23, 2006, Inergy’s shelf registration statement (File No. 333-132287) was declared effective by the
Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units, partnership
securities and debt securities, or any combination thereof. Pursuant to the shelf registration statement, Inergy is
permitted to issue these securities from time to time for general business purposes, including debt repayment,
future acquisitions, capital expenditures and working capital, or for other potential uses identified in a prospectus
supplement.
On September 10, 2009, Inergy’s new shelf registration statement (File No. 333-158066) was declared effective
by the Securities and Exchange Commission for the periodic sale of up to $1.0 billion of common units,
partnership securities and debt securities, or any combination thereof.
In June 2006, Inergy issued 4,312,500 common units, under the shelf registration statement, in a public offering,
which included 562,500 common units issued as result of the underwriters exercising their over-allotment
122
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
provision. The issuance of these common units resulted in net proceeds of $102.7 million, after deducting
underwriters’ discounts, commissions and other offering expenses. These proceeds were partially used to repay
indebtedness under the Credit Agreement with the remainder used to fund capital expenditures made in
connection with internal growth projects related to Inergy’s midstream assets.
In February 2007, Inergy issued 3,450,000 common units, under the shelf registration statement, which included
450,000 common units issued as a result of the underwriters exercising their over-allotment provision. The
issuance of these common units resulted in net proceeds of $104.5 million, after deducting underwriters’
discounts, commissions and other offering expenses. The net proceeds from this offering were used to repay
indebtedness under Inergy’s Credit Agreement.
In August 2008, Inergy issued 809,389 common units in conjunction with the acquisition of US Salt and in
October 2008, Inergy issued 309,194 common units to Blu-Gas in a private placement as a portion of the
purchase price.
In March 2009, Inergy issued 4,000,000 common units, under the shelf registration statement, and in April 2009,
the underwriters exercised their option to purchase 418,000 additional Inergy common units. Net proceeds from
the aforementioned issuances amounted to $94.3 million.
In August 2009, Inergy issued 3,500,000 common units, under the shelf registration statement, and in September
2009, the underwriters exercised their option to purchase 525,000 additional Inergy common units. Net proceeds
from the aforementioned issuances amounted to $106.9 million.
Quarterly Distributions of Available Cash
Inergy is expected to make quarterly cash distributions of all of its Available Cash, generally defined as income
(loss) before income taxes plus depreciation and amortization, less maintenance capital expenditures and net
changes in reserves established by the General Partner for future requirements. These reserves are retained to
provide for the proper conduct of the Company’s business, or to provide funds for distributions with respect to
any one or more of the next four fiscal quarters.
Distributions by Inergy in an amount equal to 100% of its Available Cash will generally be made 99% to the
common and subordinated unitholders and 1% to the General Partner, subject to the payment of incentive
distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash
distributions are achieved. To the extent there is sufficient Available Cash, the holders of common units had the
right to receive the Minimum Quarterly Distribution ($0.30 per unit), plus any arrearages, prior to any
distribution of Available Cash to the holders of subordinated units.
123
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Inergy is expected to make distributions of its Available Cash within 45 days after the end of each fiscal quarter
ending December, March, June and September to holders of record on the applicable record date. A summary of
Inergy’s quarterly distributions for the years ended September 30, 2009, 2008 and 2007, is presented below:
Record Date
November 7, 2008
February 6, 2009
May 8, 2009
August 7, 2009
Record Date
November 7, 2007
February 7, 2008
May 8, 2008
August 7, 2008
Record Date
November 7, 2006
February 7, 2007
May 8, 2007
August 7, 2007
Unit Purchase Plan
Year Ended September 30, 2009
Payment Date
November 14, 2008 . . . . . . . . . . . . .
February 13, 2009 . . . . . . . . . . . . . .
May 15, 2009 . . . . . . . . . . . . . . . . . .
August 14, 2009 . . . . . . . . . . . . . . . .
Year Ended September 30, 2008
Payment Date
November 14, 2007 . . . . . . . . . . . . .
February 14, 2008 . . . . . . . . . . . . . .
May 15, 2008 . . . . . . . . . . . . . . . . . .
August 14, 2008 . . . . . . . . . . . . . . . .
Year Ended September 30, 2007
Payment Date
November 14, 2006 . . . . . . . . . . . . .
February 14, 2007 . . . . . . . . . . . . . .
May 15, 2007 . . . . . . . . . . . . . . . . . .
August 14, 2007 . . . . . . . . . . . . . . . .
Per Unit Rate
Distribution Amount
(in millions)
$0.635
$0.645
$0.655
$0.665
$ 2.60
$ 43.2
44.4
49.2
50.4
$187.2
Per Unit Rate
Distribution Amount
(in millions)
$0.595
$0.605
$0.615
$0.625
$ 2.44
$ 38.2
39.3
40.2
41.2
$158.9
Per Unit Rate
Distribution Amount
(in millions)
$0.555
$0.565
$0.575
$0.585
$ 2.28
$ 31.2
32.1
36.2
37.3
$136.8
Inergy’s managing 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 managing 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 managing 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
124
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
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, 2009, 2008 and 2007, were
11,298 units, 11,670 units and 8,681 units, respectively. Holdings’ general partner sponsors a similar plan for
Inergy and its employees. Common units purchased through the Holdings’ unit purchase plan for the fiscal years
ended September 30, 2009, 2008 and 2007, were 5,505 units, 5,387 units and 2,667 units, respectively.
Long-Term Incentive Plan
Inergy’s managing 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 5,000,000 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
Option Agreements, which typically provide that unit options begin vesting five years from the anniversary date
of the applicable grant date. Shares issued as a result of unit option exercises are newly issued shares.
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 of the
managing general partner of Inergy. 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 not
primarily 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.
The Company granted 326,910, 60,064 and 69,520 restricted units during the years ended September 30, 2009,
2008 and 2007, respectively. The majority 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 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.
125
Inergy, L.P. and Subsidiaries
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, 2009, is as follows:
Weighted-Average
Grant Date Fair Value Number of Units
Non-vested at October 1, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted during the period ended September 30, 2009 . . . . . . . . . . . . . . . . .
Vested during the period ended September 30, 2009 . . . . . . . . . . . . . . . . . .
Forfeited during the period ended September 30, 2009 . . . . . . . . . . . . . . . .
Non-vested at September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$29.46
$19.45
$16.50
$29.27
$24.92
171,828
326,910
120,615
1,707
376,416
The weighted-average grant date fair value of restricted units granted during the year ended September 30, 2008,
amounted to $28.71. No restricted units vested during the year ended September 30, 2008. The weighted-average
grant date fair value of restricted units granted and vested during the year ended September 30, 2007, amounted
to $32.16 and $26.62, respectively. The fair value of restricted units vested during the year ended September 30,
2009, was $2.0 million. The fair value of restricted units vested during the year ended September 30, 2007, was
negligible.
The compensation expense recorded by the Company related to these restricted stock awards was $1.6 million,
$2.4 million and $0.4 million for the years ended September 30, 2009, 2008 and 2007, respectively.
Unit Options
Unit options issued under the long-term incentive plan have an exercise price equal to the fair market value of the
units on the date of the grant. In general, unit options will expire after 10 years and are subject to vesting periods
as outlined in the unit option agreement. In addition, most unit option grants made under the plan provide that the
unit options will become exercisable upon a change of control of the managing general partner or Inergy.
A summary of Inergy’s unit option activity for the years ended September 30, 2009, 2008 and 2007, is as
follows:
Outstanding at September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Canceled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Canceled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Canceled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Range of
Exercise Prices
$ 8.19 - $31.32
—
$ 8.19 - $27.14
$13.75 - $20.13
$13.75 - $31.32
—
$13.75 - $16.90
$26.51 - $27.14
$14.72 - $31.32
—
$14.72 - $16.90
$27.14 - $31.31
Weighted-
Average
Exercise
Price
$16.37
—
$11.89
$19.54
$20.25
—
$15.34
$26.87
$21.99
—
$15.46
$28.81
Number
of Units
711,964
—
325,464
56,000
330,500
—
89,135
3,500
237,865
—
50,965
5,000
Outstanding at September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$14.95 - $31.32
$23.63
181,900
Exercisable at September 30, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$14.95 - $31.32
$20.36
110,900
126
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Information regarding options outstanding and exercisable as of September 30, 2009, is as follows:
Range of Exercise Prices
$14.95 - $15.66 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$15.67 - $18.79 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$18.80 - $21.92 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$21.93 - $25.06 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$25.07 - $28.19 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$28.20 - $31.20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$31.21 - $31.32 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding
Weighted-
Average
Remaining
Contracted
Life
(years)
2.9
3.4
4.0
4.5
5.3
5.9
5.7
4.6
Exercisable
Weighted-
Average
Exercise
Price
$14.95
15.70
20.96
23.94
26.94
29.17
31.32
$23.63
Options
Exercisable
23,500
22,400
25,000
30,000
—
—
10,000
110,900
Weighted-
Average
Exercise
Price
$14.95
15.70
20.96
23.94
—
—
31.32
$20.36
Options
Outstanding
23,500
22,400
25,000
30,000
23,500
37,500
20,000
181,900
The weighted-average remaining contract lives for options outstanding and exercisable at September 30, 2009,
were approximately five years and four years, respectively. The fair value of each option grant was estimated as
of the grant date using the Black-Scholes option pricing model using the assumptions outlined in the table below.
Expected volatility was based on a combination of historical and implied volatilities of the Company’s stock over
a period at least as long as the options’ expected term. The expected life represents the period of time that the
options granted are expected to be outstanding. The risk-free rate is based on the applicable U.S. Treasury yield
curve in effect at the time of the grant of the share options.
Weighted average fair value of options granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —
Expected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.336
Distribution yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life of option in years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8.9%
5
2.3%
—
0.204
11.6%
5
3.0%
2009
2008
2007
—
0.231
7.4%
5
4.2%
The aggregate intrinsic values of options outstanding and exercisable at September 30, 2009, were $1.2 million
and $1.1 million, respectively. The aggregate intrinsic value of unit options exercised during the year ended
September 30, 2009, was $0.5 million. Aggregate intrinsic value represents the positive difference between the
Company’s closing stock price on the last trading day of the fiscal period, which was $29.78 on September 30,
2009, and the exercise price multiplied by the number of options outstanding.
As of September 30, 2009, there was $16.4 million of total unrecognized compensation cost related to unvested
share-based compensation awards granted to employees under the restricted stock and unit option plans,
including $9.3 million related to Holdings unvested share-based compensation awards. That cost is expected to
be recognized over a five-year period.
Note 10. 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 $16,500 in 2009.
The plan provides for matching contributions by Inergy for employees completing one year of service of at least
1,000 hours. Aggregate matching contributions made by Inergy were $2.1 million in fiscal 2009 and 2008, and
$1.9 million in fiscal 2007.
127
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Of Inergy’s 2,910 employees, 8% are subject to collective bargaining agreements. For the years ended
September 30, 2009, 2008 and 2007, Inergy made contributions on behalf of its union employees to union
sponsored defined benefit plans of $2.9 million, $2.7 million and $2.6 million, respectively.
Note 11. Commitments and Contingencies
Inergy periodically enters into agreements with suppliers to purchase fixed quantities of propane, distillates,
natural gas and liquids at fixed prices. At September 30, 2009, the total of these firm purchase commitments was
$225.3 million of which $220.1 million will occur over the course of the next twelve months with the balance of
$5.2 million occurring over the following twelve months. The Company also enters into non-binding agreements
with suppliers to purchase quantities of propane, distillates, natural gas and liquids at variable prices at future
dates at the then prevailing market prices.
Inergy has entered into certain purchase commitments in connection with the identified growth projects related to
the Thomas Corners and Finger Lakes midstream assets. At September 30, 2009, the total of these firm purchase
commitments was $10.4 million and the purchases associated with these commitments will 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.
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. At September 30, 2009 and 2008,
Inergy’s self-insurance reserves were $19.3 million and $17.4 million, respectively.
Note 12. Related Party Transactions
In connection with the acquisition of assets from United Propane, Inc. on July 31, 2003, the Company entered
into ten leases of real property formerly used by United Propane (now known as Bonavita, Inc.) in its business.
Five of these leases are with United Propane, three of the leases are with Pascal Enterprises, Inc. and two with
Robert A. Pascal. Each of these leases provided for an initial five-year term, and was renewable for up to two
additional terms of five years each. During the initial term of these leases the Company was required to make
monthly rental payments totaling $59,167, of which $17,167 was payable to United Propane, $16,800 was
payable to Pascal Enterprises and $25,200 was payable to Mr. Pascal. During fiscal 2008, the Company exercised
its renewal option on six of these leases for an additional five-year term each. Three of these leases are with
United Propane, two of these leases are with Mr. Pascal and one is with Pascal Enterprises. The Company is now
required to make monthly rental payments totaling $50,947, of which $8,400 is payable to United Propane,
$30,997 is payable to Mr. Pascal and $11,550 is payable to Pascal Enterprises.
128
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Robert A. Pascal is the sole shareholder of Bonavita, Inc., Pascal Enterprises and United Leasing. Mr. Pascal
retired from the Company’s board of directors on December 12, 2008.
On occasion, Holdings reimburses the Company for expenses paid on behalf of Holdings. The expenses that are
reimbursed predominantly include insurance and professional fees. These expenses for the years ended
September 30, 2009, 2008 and 2007, amounted to $0.5 million, $0.2 million and $0.4 million, respectively. When
the Company has a receivable from Holdings, it is included in prepaid expenses and other current assets on the
Company’s consolidated balance sheets. At September 30, 2009 and 2008, Inergy had $0.1 million and $0.2
million, respectively, due from Holdings.
The managing general partner and its affiliates will not receive any management fee or other compensation for
the management of the Company. The managing general partner and its affiliates will be reimbursed, however,
for direct and indirect expenses incurred on Inergy’s behalf. The expense reimbursement to the managing general
partner and its affiliates was $3.1 million for the fiscal year ended September 30, 2009, and $3.5 million for the
fiscal years ended September 30, 2008 and 2007, with the reimbursement related primarily to personnel costs.
During fiscal 2009, Inergy Holdings received $48.1 million in distributions related to its 0.8% general partner
interest and incentive distribution rights and $12.3 million related to its 7.8% limited partner interest.
Note 13. Segments
Inergy’s financial statements reflect two operating and reportable segments: propane operations and midstream
operations. Inergy’s propane operations include propane sales to end users, the sale of propane-related appliances
and service work for propane-related equipment, the sale of distillate products and wholesale distribution of
propane and marketing and price risk management services to other users, retailers and resellers of propane.
Inergy’s midstream operations include storage of natural gas for third parties, fractionation of natural gas liquids,
processing of natural gas, distribution of natural gas liquids and the production and sale of salt. Results of
operations for acquisitions that occurred during the year ended September 30, 2009, are included in the propane
segment.
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 propane segment.
129
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, 2009
Propane
Operations
Midstream
Operations
Intersegment
Operations
Corporate
Assets
Total
Retail propane revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale propane revenues . . . . . . . . . . . . . . . . . . . . .
Storage, fractionation and other midstream revenues . .
Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Propane-related appliance sales revenues . . . . . . . . . . .
Retail service revenues . . . . . . . . . . . . . . . . . . . . . . . . . .
Rental service and other revenues . . . . . . . . . . . . . . . . .
Distillate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . .
. . . . . .
Expenditures for property, plant and equipment
$736.7
368.2
—
16.8
21.4
17.8
27.5
125.7
471.0
139.6
277.9
697.0
14.0
$ —
19.7
220.8
16.9
—
—
—
—
103.4
51.6
96.4
847.1
203.7
$—
(0.2)
(0.7)
—
—
—
—
—
(0.7)
—
—
—
—
$ — $ 736.7
387.7
220.1
33.7
21.4
17.8
27.5
125.7
573.7
191.2
374.3
1,555.2
218.6
—
—
—
—
—
—
—
—
—
—
11.1
0.9
Year Ended September 30, 2008
Propane
Operations
Midstream
Operations
Intersegment
Operations
Corporate
Assets
Total
Retail propane revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale propane revenues . . . . . . . . . . . . . . . . . . . . .
Storage, fractionation and other midstream revenues . .
Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Propane-related appliance sales revenues . . . . . . . . . . .
Retail service revenues . . . . . . . . . . . . . . . . . . . . . . . . . .
Rental service and other revenues . . . . . . . . . . . . . . . . .
Distillate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . .
. . . . . .
Expenditures for property, plant and equipment
$840.7
509.1
—
16.4
22.2
17.6
27.7
139.1
409.8
193.0
275.9
689.3
13.8
$ —
37.0
252.3
17.3
—
—
—
—
92.9
46.3
167.1
575.5
196.2
$—
—
(0.5)
—
—
—
—
—
(0.5)
—
—
—
—
$ — $ 840.7
546.1
251.8
33.7
22.2
17.6
27.7
139.1
502.2
239.3
443.0
1,275.0
211.5
—
—
—
—
—
—
—
—
—
—
10.2
1.5
Year Ended September 30, 2007
Propane
Operations
Midstream
Operations
Intersegment
Operations
Corporate
Assets
Total
Retail propane revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale propane revenues . . . . . . . . . . . . . . . . . . . . .
Storage, fractionation and other midstream revenues . .
Transportation revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Propane-related appliance sales revenues . . . . . . . . . . .
Retail service revenues . . . . . . . . . . . . . . . . . . . . . . . . . .
Rental service and other revenues . . . . . . . . . . . . . . . . .
Distillate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . .
. . . . . .
Expenditures for property, plant and equipment
$733.2
393.8
—
12.3
23.0
16.7
24.7
92.1
398.8
187.7
261.5
672.4
13.9
$ —
23.4
152.7
11.7
—
—
—
—
58.7
27.5
85.7
319.1
86.5
$—
—
(0.5)
—
—
—
—
—
(0.5)
—
—
—
—
$ — $ 733.2
417.2
152.2
24.0
23.0
16.7
24.7
92.1
457.0
215.2
347.2
1,000.3
101.4
—
—
—
—
—
—
—
—
—
—
8.8
1.0
130
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
Note 14. 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 2009
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) per limited partner unit:(a) . . . . . . . . . . . . .
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fiscal 2008
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) per limited partner unit:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$534.0
174.3
74.5
57.2
$ 0.91
$ 0.91
$514.6
137.2
52.3
36.9
$ 0.57
$ 0.57
$570.1
212.1
109.8
91.3
$235.0
97.3
3.4
(14.3)
$231.5
90.0
(14.6)
(32.8)
$ 1.55
$ 1.55
$ (0.48)
$ (0.48)
$ (0.79)
$ (0.79)
$648.2
188.6
97.2
82.0
$375.2
88.7
(4.9)
(20.7)
$340.9
87.7
(17.5)
(33.1)
$ 1.46
$ 1.46
$ (0.60)
$ (0.60)
$ (0.85)
$ (0.85)
(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.
Note 15. Subsequent Events
The Company has identified subsequent events requiring disclosure through November 30, 2009, the date of the
filing of this Form 10-K.
On November 13, 2009 a quarterly distribution of $0.675 per limited partner unit was paid to unitholders of
record on November 6, 2009 with respect to the fourth fiscal quarter of 2009, which totaled $55.2 million.
On November 24, 2009, the Company entered into a secured credit facility which provides borrowing capacity of
up to $525 million in the form of a $450 million general partnership credit facility and a $75 million working
capital credit facility. This facility replaces its former senior credit facility due 2010. This new facility will
mature on November 22, 2013. Borrowings under this new facility 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.
The new secured credit facility contains various affirmative and negative covenants and default provisions, as
well as requirements with respect to the maintenance of specified financial ratios and limitations on making
investments, permitting liens and entering into other debt obligations. All borrowings under the facility bear
interest, at the Company’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 1.50% to 2.75%; or
131
Inergy, L.P. and Subsidiaries
Notes to Consolidated Financial Statements—(Continued)
•
the Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 2.50% to
3.75%.
Certain counterparties have elected to call their respective interest rate swap positions. The aggregate notional
amount associated with these swaps amounts to $125 million. These swaps will be called in December 2009 and
the Company is currently evaluating its options to manage its interest rate risk.
132
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.
SIGNATURES
Dated: November 30, 2009
INERGY, L.P.
By Inergy GP, LLC
(its managing general partner)
By
/s/
JOHN J. SHERMAN
John J. Sherman, President
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 managing general partner of Inergy, L.P., the
registrant, in the capacities and on the dates indicated.
Date
November 30, 2009
Signature and Title
/S/
JOHN J. SHERMAN
John J. Sherman, President, Chief Executive Officer and Director
(Principal Executive Officer)
November 30, 2009
/S/ R. BROOKS SHERMAN, JR.
R. Brooks Sherman, Jr.,
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
November 30, 2009
November 30, 2009
November 30, 2009
November 30, 2009
/S/ PHILLIP L. ELBERT
Phillip L. Elbert,
President and Chief Operating Officer
/S/ WARREN H. GFELLER
Warren H. Gfeller, Director
/S/ ARTHUR B. KRAUSE
Arthur B. Krause, Director
/S/ ROBERT D. TAYLOR
Robert D. Taylor, Director
133
Inergy, L.P. and Subsidiaries
Valuation and Qualifying Accounts
(in millions)
Schedule II
Year Ended September 30,
Allowance for doubtful accounts
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at
beginning
of period
Charged
to costs
and
expenses
Other
Additions
Deductions
(write-offs)
Balance
at end
of
period
$6.4
3.4
2.9
$3.7
5.7
3.3
$0.3
0.5
0.5
$(7.7)
(3.2)
(3.3)
$2.7
6.4
3.4
134
Exhibit 31.1
CERTIFICATIONS
I, John J. Sherman, certify that:
1. I have reviewed this annual report on Form 10-K of Inergy, L.P. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in
this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of
an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: November 30, 2009
/s/
JOHN J. SHERMAN
John J. Sherman
President and Chief Executive Officer
Exhibit 31.2
CERTIFICATIONS
I, R. Brooks Sherman, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of Inergy, L.P. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in
this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of
an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: November 30, 2009
/S/ R. BROOKS SHERMAN, JR.
R. Brooks Sherman, Jr.
Executive Vice President and Chief Financial Officer
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
Exhibit 32.1
In connection with the Annual Report of Inergy, L.P. (the “Company”) on Form 10-K for the period ended
September 30, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I,
John J. Sherman, Chief Executive Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
Date: November 30, 2009
/S/
JOHN J. SHERMAN
John J. Sherman
Chief Executive Officer
A signed original of this written statement required by Section 906, or other document authenticating,
acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of
this written statement required by Section 906, has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission or its staff upon request.
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
Exhibit 32.2
In connection with the Annual Report of Inergy, L.P. (the “Company”) on Form 10-K for the period ended
September 30, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I,
R. Brooks Sherman, Jr., Chief Financial Officer of Inergy, L.P., certify, pursuant to 18 U.S.C. § 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
Date: November 30, 2009
/S/ R. BROOKS SHERMAN, JR.
R. Brooks Sherman, Jr.
Chief Financial Officer
A signed original of this written statement required by Section 906, or other document authenticating,
acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of
this written statement required by Section 906, has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission or its staff upon request.
Offi cers – Inergy, L.P.
JOHN J. SHERMAN*
President and Chief Executive Offi cer
PHILLIP L. ELBERT*
Chief Operating Offi cer and
President, Inergy Propane
R. BROOKS SHERMAN, JR.*
Executive Vice President and
Chief Financial Offi cer
Propane Operations
Leadership
ANDREW L. ATTERBURY
Senior Vice President,
Corporate Development
CARL A. HUGHES
Senior Vice President,
Business Development
WILLIAM R. MOLER
Senior Vice President,
Inergy Midstream
LAURA L. OZENBERGER*
Senior Vice President and
General Counsel
WILLIAM C. GAUTREAUX
President, Inergy Services
MICHAEL J. CAMPBELL
Vice President and Treasurer
STANLEY A. ROSS
Vice President and
Corporate Controller
TOM HAIAR
Senior Vice President/Chief Operating
Offi cer – Mid-Continent U.S.
TED JEFFCOAT
Senior Vice President/Chief Operating
Offi cer – Eastern U.S.
JOE DONNELL
President,
L&L Transportation
TOM WRIGHT
Director,
Fleet Operations
MARK ANDERLE
President,
Texas/Oklahoma Division
JIM CROSS
President,
Michigan Division
ROBERT “PAT” HOUSER
President,
Ohio Division
GARY KOMOSA
President,
Illinois Division
DAN MANSON
President,
Indiana Division
ED MORENO
President,
Wisconsin Division
JEFF BRUNNER
President,
Southeastern Pennsylvania
CHRIS CAFARELLA
President,
Mid-Atlantic Division
JAY CATES
President,
New York/Pennsylvania Division
JAMES DEVINS
President,
Virginia/North Carolina Division
DAVE FEHELY
President,
Western New England Division
SAM HODGES
President,
Florida Division
MIKE VAUGHN
President,
Mississippi/Alabama Division
STEVE MERHAR
President,
Eastern New England Division
JOHN MILLER
President,
Eastern Ohio/Western
Pennsylvania Division
Midstream Operations
Leadership
BARRY CIGICH
Vice President,
Operations – Inergy Midstream
MITCHELL DASCHER
President, US Salt
RON HAPPACH
Vice President, Commercial
Operations – Inergy Midstream
RICHARD C. KREUL
Vice President, Inergy Services
DON KRIDER
Vice President, Commercial
Operations – US Salt
.P.L ,ygrenI - srotceriD
snoitaleR rotsevnI
K-1 Information
tnegA refsnarT
JOHN J. SHERMAN
PHILLIP L. ELBERT
WARREN H. GFELLER
ARTHUR B. KRAUSE
ROBERT D. TAYLOR
MICHAEL CAMPBELL
Two Brush Creek Blvd., Suite 200
Kansas City, MO 64112
1-877-4-INERGY
investorrelations@inergyservices.com
FOR INERGY, L.P. (NRGY)
call 1-800-230-1134
FOR INERGY HOLDINGS, L.P. (NRGP)
call 1-866-792-0046
AMERICAN STOCK TRANSFER
& TRUST COMPANY
59 Maiden Lane, Plaza Level
New York, NY 10038
Shareholder Services: 1-800-937-5449
Info@AmStock.com
Directors - Inergy Holdings, L.P.
JOHN J. SHERMAN
WARREN H. GFELLER
ARTHUR B. KRAUSE
RICHARD T. O’BRIEN
*Also Offi cer for Inergy Holdings, L.P.
Two Brush Creek Boulevard, Suite 200
Kansas City, MO 64112
P: 816-842-8181 F: 816-531-0746
www.InergyLP.com