UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
þ ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the
fiscal year ended December 31, 2009
OR
o 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: 1-33266
DUNCAN
ENERGY PARTNERS L.P.
(Exact
name of Registrant as Specified in Its Charter)
|
Delaware
|
20-5639997
|
||
|
(State
or Other Jurisdiction of
|
(I.R.S.
Employer Identification No.)
|
||
|
Incorporation
or Organization)
|
|||
|
1100
Louisiana Street, 10th Floor, Houston,
Texas 77002
|
|||
|
(Address
of Principal Executive Offices) (Zip
Code)
|
|||
|
(713)
381-6500
|
|||
|
(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 New York Stock Exchange |
Securities to be registered pursuant
to Section 12(g) of the Act: None.
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes o No þ
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes o No þ
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 þ No o
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 o No
o
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. o
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. (Check one):
| Large accelerated filer o | Accelerated filer þ | |
| Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o No þ
The
aggregate market value of the Duncan Energy Partners L.P.’s (or “DEP’s”) common
units held by non-affiliates at June 30, 2009, was approximately $361.6 million,
based on the closing price of such equity securities in the daily composite list
for transactions on the New York Stock Exchange. This figure excludes
common units beneficially owned by certain affiliates, including Dan L. Duncan
and Enterprise Products Operating LLC. There were 57,676,987 common
units of DEP outstanding at February 1, 2010.
TABLE
OF CONTENTS
SIGNIFICANT
RELATIONSHIPS REFERENCED IN THIS
ANNUAL
REPORT
Unless the context requires otherwise,
references to “we,” “us,” “our,” or “Duncan Energy Partners” are intended to
mean the business and operations of Duncan Energy Partners L.P. and its
consolidated subsidiaries. References to “DEP GP” mean DEP Holdings, LLC,
which is our general partner. References to “DEP OLP” mean DEP Operating
Partnership, L.P., which is a wholly owned subsidiary of Duncan Energy Partners
through which Duncan Energy Partners conducts substantially all of its
business.
References to “Enterprise Products
Partners” mean the business and operations of Enterprise Products Partners L.P.
and its consolidated subsidiaries. Enterprise Products Partners is a
publicly traded Delaware limited partnership, the common units of which are
listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”
References to “EPGP” mean Enterprise
Products GP, LLC, which is the general partner of Enterprise Products
Partners. References to “EPO” mean Enterprise Products Operating LLC,
which is a wholly owned subsidiary of Enterprise Products Partners through which
Enterprise Products Partners conducts substantially all of its business, and its
consolidated subsidiaries. EPO beneficially owns 100% of DEP GP and
is a significant owner of our common units. Enterprise Products
Partners consolidates our financial statements with those of its
own.
References to “TEPPCO” and “TEPPCO GP”
mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC
(which is the general partner of TEPPCO), respectively, prior to their mergers
with subsidiaries of Enterprise Products Partners. On October 26,
2009, Enterprise Products Partners completed the mergers with TEPPCO and TEPPCO
GP. On October 27, 2009, Enterprise Products Partners’ TEPPCO and
TEPPCO GP equity interests were contributed to EPO, and TEPPCO and TEPPCO GP
became wholly owned subsidiaries of EPO.
References to “Enterprise
GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded Delaware
limited partnership, the units of which are listed on the NYSE under the ticker
symbol “EPE.” Enterprise GP Holdings owns EPGP. The
general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”),
a wholly owned subsidiary of Dan Duncan LLC, all of the membership interests of
which are owned by Dan L. Duncan.
References to “Energy Transfer Equity”
mean the business and operations of Energy Transfer Equity, L.P. and its
consolidated subsidiaries, which include Energy Transfer Partners, L.P.
(“ETP”). Energy Transfer Equity is a publicly traded Delaware limited
partnership, the common units of which are listed on the NYSE under the ticker
symbol “ETE.” The general partner of Energy Transfer Equity is LE GP,
LLC (“LE GP”). ETP is a publicly traded Delaware limited partnership,
the common units of which are listed on the NYSE under the ticker symbol
“ETP.”
References to the “DEP I Midstream
Businesses” collectively refer to (i) Mont Belvieu Caverns, LLC (“Mont Belvieu
Caverns”); (ii) Acadian Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex
Propylene Pipeline L.P. (“Lou-Tex Propylene”), including its general partner;
(iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), including its general
partner; and (v) South Texas NGL Pipelines, LLC (“South Texas
NGL”). We acquired controlling ownership interests in the DEP I
Midstream Businesses from EPO effective February 1, 2007 in a drop down
transaction (the “DEP I drop down”) in connection with our initial public
offering.
References to the “DEP II Midstream
Businesses” collectively refer to (i) Enterprise GC, L.P. (“Enterprise GC”);
(ii) Enterprise Intrastate L.P. (“Enterprise Intrastate”); and (iii) Enterprise
Texas Pipeline LLC (“Enterprise Texas”). We acquired controlling
ownership interests in the DEP II Midstream Businesses from EPO on December 8,
2008 in a drop down transaction (the “DEP II drop down”). Our
ownership interests in the DEP II Midstream Businesses are held by Enterprise
Holding III, L.L.C., which is a wholly owned subsidiary of DEP
OLP. Ownership interests in the DEP II Midstream Businesses that were
retained by EPO are held by its wholly owned subsidiary, Enterprise GTM Holdings
L.P.
Within the context of our financial
information, references to “former owners” mean EPO’s ownership interests in the
DEP I and DEP II Midstream Businesses prior to the effective date of the related
drop down transactions.
References to “Evangeline” mean our
aggregate 49.51% equity method investment in Evangeline Gas Pipeline Company,
L.P. (“EGP”) and Evangeline Gas Corp (“EGC”).
References to “EPCO” mean Enterprise
Products Company (formerly EPCO, Inc.) and its privately held
affiliates. We, Enterprise Products Partners, EPO, DEP GP, EPGP,
Enterprise GP Holdings and EPE Holdings are affiliates under the common control
of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of
EPCO.
References to “Employee Partnerships”
mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit
III, L.P. (EPE Unit III), Enterprise Unit L.P. (“Enterprise Unit”) and EPCO Unit
L.P. (“EPCO Unit”), collectively, all of which are privately held affiliates of
EPCO.
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This
annual report on Form 10-K for the year ended December 31, 2009 (“annual
report”) contains various forward-looking statements and information that are
based on our beliefs and those of our general partner, as well as assumptions
made by us and information currently available to us. When used in
this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,”
“goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,”
“may,” “potential” and similar expressions and statements regarding our plans
and objectives for future operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A of this annual report. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove incorrect, our
actual results may vary materially from those anticipated, estimated, projected
or expected. You should not put undue reliance on any forward-looking
statements. The forward-looking statements in this annual report
speak only as of the date hereof. Except as required by federal and
state securities laws, we undertake no obligation to publicly update or revise
any forward-looking statements, whether as a result of new information, future
events or any other reason.
General
We are a publicly traded Delaware
limited partnership, the common units of which are listed on the NYSE under the
ticker symbol “DEP.” Duncan Energy Partners was formed in September
2006 and did not own any assets prior to February 5, 2007, which was the date it
completed its initial public offering and acquired controlling interests in the
DEP I Midstream Businesses from EPO. The business purpose of Duncan
Energy Partners is to acquire, own and operate a diversified portfolio of
midstream energy assets and to support the growth objectives of EPO and other
affiliates under common control. Duncan Energy Partners is engaged in
the business of: (i) natural gas liquids (“NGLs”) transportation, fractionation
and marketing; (ii) storage of NGL and petrochemical products; (iii)
transportation of petrochemical products; and (iv) the gathering,
transportation, marketing and storage of natural gas. We conduct
substantially all of our business through DEP OLP. Our principal
executive offices are located at 1100 Louisiana Street, 10th
Floor, Houston, Texas 77002; our telephone number is (713) 381-6500 and our
website address is www.deplp.com.
Duncan Energy Partners was owned 99.3%
by its limited partners and 0.7% by its general partner, DEP GP, at December 31,
2009. EPO owned approximately 58.6% of our common units and 100% of
DEP GP at December 31, 2009. DEP GP is responsible for managing the
business and operations of Duncan Energy Partners. EPCO provides all
of our employees and certain administrative services to us.
Our relationship with EPO is one of our
principal business advantages. Our assets connect to various
midstream energy assets of EPO and form integral links within EPO’s value chain
of assets. We believe that the operational significance of our assets
to EPO, as well as the alignment of our respective economic interests in these
assets, will result in a collaborative effort between us and EPO to promote the
operational efficiency of our assets and maximize their value. See
Item 13 within this annual report for additional information regarding our
relationships with EPCO and EPO.
The
following information summarizes the businesses acquired and consideration we
provided in connection with the DEP I and DEP II drop down
transactions.
DEP
I Drop Down
Effective
February 1, 2007, EPO contributed to us a 66% controlling equity interest in
each of the DEP I Midstream Businesses in a drop down
transaction. EPO retained the remaining 34% noncontrolling equity
interest in each of these businesses. As consideration for these
equity interests, we paid $459.5 million in cash and issued 5,351,571 common
units to EPO. The cash portion of this consideration was financed
with $198.9 million in borrowings under our $300 million unsecured revolving
credit facility (the “Revolving Credit Facility”) and $260.6 million of the
$290.5 million of net proceeds from our initial public offering. The
following is a brief description of the assets and operations of the DEP I
Midstream Businesses:
|
§
|
Mont
Belvieu Caverns owns 34 underground salt dome storage caverns located in
Mont Belvieu, Texas, having an NGL and related product storage capacity of
approximately 100 million barrels (“MMBbls”), and a brine system with
approximately 20 MMBbls of above ground storage capacity and two brine
production wells.
|
|
§
|
Acadian
Gas is engaged in the gathering, transportation, storage and marketing of
natural gas in south Louisiana, utilizing over 1,000 miles of
pipelines having an aggregate throughput capacity of 1.0 billion cubic
feet per day (“Bcf/d”). Acadian Gas also owns a 49.51% equity
interest in Evangeline, which owns a 27-mile natural gas pipeline located
in southeast Louisiana.
|
|
§
|
Lou-Tex
Propylene owns a 263-mile pipeline used to transport chemical-grade
propylene from Sorrento, Louisiana to Mont Belvieu,
Texas.
|
|
§
|
Sabine
Propylene owns a 21-mile pipeline used to transport polymer-grade
propylene from Port Arthur, Texas to a pipeline interconnect in Cameron
Parish, Louisiana.
|
|
§
|
South
Texas NGL owns a 297-mile pipeline system used to transport NGLs from our
Shoup and Armstrong NGL fractionation facilities in south Texas to Mont
Belvieu, Texas.
|
DEP
II Drop Down
On December 8, 2008, EPO contributed to
us the following controlling equity interests in a second drop down transaction:
(i) a 66% general partner interest in Enterprise GC, (ii) a 51% general partner
interest in Enterprise Intrastate and (iii) a 51% membership interest in
Enterprise Texas. As consideration for these equity interests, we
paid $280.5 million in cash and issued 37,333,887 Class B units to EPO (which
automatically converted on a one-for-one basis to common units in February
2009). The cash portion of this consideration was financed with
$280.0 million in borrowings under our $300.0 million senior unsecured term loan
agreement (the “Term Loan Agreement”) and $0.5 million of net proceeds from an
equity offering to EPO. The market value of the Class B units at the
time of issuance was approximately
$449.5
million. The following is a brief description of the assets and
operations of the DEP II Midstream Businesses:
|
§
|
Enterprise
GC operates and owns: (i) two NGL fractionation facilities, Shoup and
Armstrong, located in south Texas; (ii) a 1,020-mile NGL pipeline system
located in south Texas; and (iii) 1,112 miles of natural gas gathering
pipelines located in south and west Texas. Enterprise GC’s
natural gas gathering pipelines include: (i) the 262-mile Big Thicket
Gathering System located in southeast Texas; (ii) the 660-mile Waha system
located in the Permian Basin of west Texas; and (iii) the 190-mile TPC
Offshore gathering system located in south
Texas.
|
|
§
|
Enterprise
Intrastate operates and owns an undivided 50% interest in the assets
comprising the 641-mile Channel natural gas pipeline, which extends from
the Agua Dulce Hub in south Texas to Sabine, Texas located on the
Texas/Louisiana border.
|
|
§
|
Enterprise
Texas owns the 6,560-mile Enterprise Texas natural gas pipeline system,
which includes the Sherman Extension, and leases the Wilson natural gas
storage facility. The Enterprise Texas system, along with the
Waha, TPC Offshore and Channel pipeline systems, comprise our Texas
Intrastate System.
|
Generally, to the extent that the DEP
II Midstream Businesses collectively generate cash sufficient to pay
distributions to EPO and us, such cash will be distributed first to us (based on
an initial defined investment of $730.0 million) and then to EPO in amounts
sufficient to generate an aggregate initial annualized return on their
respective investments of 11.85%. Effective January 1, 2010, the
annualized return increased by 2.0% to 12.087%. Distributions in
excess of these amounts will be distributed 98% to EPO and 2% to
us. Income and loss of the DEP II Midstream Businesses are first
allocated to EPO and us based on each entity’s percentage interest of 77.4% and
22.6%, respectively, and then in a manner that in part follows the cash
distributions.
For detailed information regarding
EPO’s noncontrolling interest in the DEP I and DEP II Midstream Businesses, see
Note 13 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
Business
Strategy
Our
primary business objectives are to maintain and, over time, to increase our cash
available for distribution to unitholders. Our business strategies to
achieve these objectives are to:
|
§
|
optimize
the benefits of our economies of scale, strategic location and pipeline
connections serving natural gas, NGL, petrochemical and refining
customers;
|
|
§
|
manage
our portfolio of midstream energy assets to minimize volatility in our
cash flows;
|
|
§
|
invest
in organic growth capital projects to capitalize on market opportunities
that expand our asset base and generate additional cash
flow; and
|
|
§
|
pursue
acquisitions of assets and businesses from related parties, or in
accordance with our business opportunity agreements, from third
parties.
|
As noted above, part of our business
strategy involves expansion through growth capital projects. We
expect that these projects will enhance our existing asset base and provide us
with additional growth opportunities in the future. For a discussion
of our capital spending program, see “Liquidity and Capital Resources – Capital
Expenditures,” included under Item 7 of this annual report.
Basis
of Financial Statement Presentation
See Note 1 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report for information
regarding the basis of presentation of our general purpose financial
statements. Such information is incorporated by reference into this
Item 1 and 2 discussion.
Financial
Information by Business Segment
For detailed financial information
regarding our business segments, see Note 14 of the Notes to Consolidated
Financial Statements included under Item 8 within this annual
report. Such financial information is incorporated by reference into
this Item 1 and 2 discussion.
Significant
Recent Developments
Haynesville
Extension
In October 2009, we and EPO announced
plans to extend our Acadian Gas System into the rapidly growing Haynesville
Shale natural gas supply basin in northwest Louisiana (the “Haynesville
Extension”). In November 2009, we received additional firm
transportation commitments from shippers, which will support an increase to the
capacity of the Haynesville Extension pipeline project. The
transportation capacity of our 249-mile Haynesville Extension pipeline has been
increased from 1.4 Bcf/d, as originally designed, to 2.1 Bcf/d of natural gas
and will extend from the Haynesville region to interconnects in central
Louisiana with the existing Acadian Gas System. The pipeline is
expected to be placed into service during the third quarter of 2011 and be part
of our Natural Gas Pipelines & Services business segment.
The Haynesville Extension will provide
producers in the Haynesville Shale natural gas supply basin with much needed
takeaway capacity, including access to more than 150 end-use markets along the
Mississippi River corridor between Baton Rouge and New Orleans. In
addition, shippers will be able to access our Napoleonville salt dome storage
cavern and have the ability to make physical deliveries into the Henry Hub and
benefit from additional pricing points. The Haynesville Extension
will also allow shippers to reach nine interstate pipeline systems.
We currently own a 66% equity interest
in the entities that own the Acadian Gas System, with EPO owning the remaining
34% equity interest. We and EPO are in discussions as to the funding
and related aspects of the Haynesville Extension project.
Service
Begins on Sherman Extension Pipeline
In late February 2009, we and EPO
announced that construction had been completed on the 173-mile Sherman Extension
expansion of our Texas Intrastate System, which extends through the heart of the
prolific Barnett Shale natural gas production basin of north
Texas. The completion of the Sherman Extension adds 1.2 Bcf/d of
incremental natural gas takeaway capacity from the region, while providing
producers in the Barnett Shale, and as far away as the Waha area of west Texas,
with greater flexibility to reach the most attractive natural gas
markets. The Texas Intrastate System is part of our Natural Gas
Pipelines & Services business segment through interconnections with
pipelines that serve the Midwest and Northeast regions of the United
States.
For additional information regarding
these and other recent developments during 2009, see “Significant Recent
Developments” included under Item 7 of this annual report, which is incorporated
by reference into this Item 1 and 2 discussion.
Segment
Discussion
We have
three reportable business segments:
|
§
|
Natural
Gas Pipelines & Services;
|
|
§
|
NGL
Pipelines & Services; and
|
|
§
|
Petrochemical
Services.
|
Our business segments are generally
organized and managed according to the type of services rendered (or
technologies employed) and products produced and/or sold.
The following sections present an
overview of our business segments, including information regarding the principal
products produced, services rendered, properties owned, seasonality and
competition. Our results of operations and financial condition are
subject to a variety of risks. For information regarding our risk
factors, see Item 1A of this annual report.
Our business activities are subject to
various federal, state and local laws and regulations governing a wide variety
of topics, including commercial, operational, environmental, safety and other
matters. For a discussion of the principal effects such laws and
regulations have on our business, see “Regulation” and “Environmental and Safety
Matters” included within this Item 1 and 2.
A related party, EPO, is our largest
customer and accounted for 33.8% of our consolidated revenues for
2009. Evangeline, another related party, was our largest customer
during 2008 and 2007 and accounted for 22.7% and 21.7% of our consolidated
revenues each year, respectively. See Note 15 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual report
for information regarding our related party revenues from EPO and
Evangeline. Related party revenues from Evangeline are attributable
to the sale of natural gas and are presented in our Natural Gas Pipelines &
Services business segment. Sales to EPO totaled $331.4 million for
the year ended December 31, 2009. Sales to Evangeline totaled $362.9
million and $264.2 million for the years ended December 31 2008 and 2007,
respectively.
Our largest non-affiliated customer is
Exxon Mobil Corporation and its affiliates (collectively, “Exxon Mobil”), which
accounted for 7.5%, 10.0% and 7.6% of our consolidated revenues in 2009, 2008
and 2007, respectively. The majority of our revenues from Exxon Mobil
is derived from the sale and transportation of natural gas and is presented in
our Natural Gas Pipelines & Services business segment. Sales to
Exxon Mobil totaled $73.4 million, $159.2 million and $93.2 million for the
years ended December 31, 2009, 2008 and 2007, respectively.
As generally used in the energy
industry and in this document, the identified terms have the following
meanings:
|
/d
|
=
per day
|
|
BBtus
|
=
billion British thermal units
|
|
Bcf
|
=
billion cubic feet
|
|
MBPD
|
=
thousand barrels per day
|
|
MBbls
|
=
thousand barrels
|
|
MMBbls
|
=
million barrels
|
|
MMBtus
|
=
million British thermal units
|
|
MMcf
|
=
million cubic feet
|
For information regarding our results
of operations, including significant measures of historical throughput and
fractionation rates, see Item 7 of this annual report. In addition,
certain of our operations entail the use of derivative
instruments. For information regarding our use of commodity
derivative instruments, see Note 6 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
Natural
Gas Pipelines & Services
Our Natural Gas Pipelines &
Services business segment includes approximately 9,400 miles of onshore natural
gas pipeline systems that provide for the gathering and transportation of
natural gas in Louisiana and Texas. We lease natural gas storage
facilities located in Texas and Louisiana. This segment also includes
our related natural gas marketing activities.
Natural
gas pipelines and related marketing activities. Our
natural gas pipeline systems provide for the gathering and transportation of
natural gas from major producing regions such as the Barnett Shale, Permian and
Eagle Ford natural gas supply basins and from offshore developments in the Gulf
of Mexico through connections with offshore pipelines. We also
recently announced our intention to expand our Acadian Gas System to provide
services to producers in the Haynesville Shale natural gas supply basin in
northwest Louisiana. Our natural gas pipelines receive natural gas
from producers, other pipelines or shippers through system interconnects and
redeliver the natural gas to processing facilities, local gas distribution
companies, industrial or municipal customers or to other pipelines.
Our natural gas pipelines typically
generate revenues from transportation agreements whereby shippers are billed a
fee per unit of volume transported (typically per MMBtu) multiplied by the
volume gathered or delivered. The transportation fees charged under
these arrangements are either contractual or regulated by governmental agencies,
including the Texas Railroad Commission. Certain of our natural gas
pipelines offer firm capacity reservation services whereby the shipper pays a
contractually stated fee based on the level of throughput capacity reserved in
our pipelines whether or not the shipper actually utilizes such
capacity. In connection with our natural gas transportation services
and marketing activities, intrastate natural gas pipelines (such as our Acadian
Gas System) may also purchase natural gas from producers and other suppliers for
transport and resale to customers such as electric utility companies, local
natural gas distribution companies, industrial users and other natural gas
marketing companies.
Our natural gas marketing activities
generate revenues from the sale and delivery of natural gas obtained from
third-party well-head purchases, regional natural gas processing plants and the
open market. In general, sales prices referenced in the contracts
utilized within our natural gas marketing activities are market-based and may
include pricing differentials for such factors as delivery
location. The results of operations for our natural gas pipelines and
related marketing activities are generally dependent upon the volume of natural
gas transported and/or sold and amounts charged to customers.
We are exposed to commodity price risk
to the extent that we take title to natural gas volumes in connection with our
natural gas marketing activities. For example, on certain segments of
our Texas Intrastate System, we purchase natural gas from certain producers
and resell the natural gas to third parties. In addition, Acadian Gas
enters into a limited number of offsetting derivatives that effectively fix the
price of natural gas for certain of its customers. We use derivative
instruments to mitigate our exposure to commodity price risks associated with
our natural gas pipelines and services business. For more information
regarding our use of derivative instruments, see Note 6 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
Underground
natural gas storage. We lease underground salt dome natural
gas storage caverns that are integral components of our Texas Intrastate and
Acadian Gas Systems. These natural gas storage facilities are
designed for sustained periods of high natural gas deliveries, including the
ability to quickly switch from full injection to full withdrawal modes of
operation. The ability of underground salt dome storage caverns to
handle high levels of injections and withdrawals of natural gas benefits
customers who desire the ability to meet load swings and to cover major supply
interruption events, such as hurricanes and temporary losses of
production. High injection and withdrawal rates allow customers to
take advantage of periods of volatile natural gas prices and respond quickly in
situations where they have natural gas imbalance issues on pipelines connected
to the storage facilities.
Under our natural gas storage
contracts, there are typically two components of revenues: (i) monthly demand
payments, which are associated with a customer’s storage capacity reservation
and paid regardless of actual usage, and (ii) storage fees per unit of volume
stored at our facilities.
Seasonality. Typically, our natural gas
pipelines experience higher throughput rates during the summer months as natural
gas-fired power generation utilities increase their output to meet residential
and commercial demand for electricity used for air
conditioning. Higher throughput rates are also experienced in the
winter months as natural gas is used to meet residential and commercial heating
requirements. Likewise, this seasonality also impacts the timing of
injections and withdrawals at our natural gas storage facilities.
Competition. Within their market areas,
our natural gas pipelines compete with other natural gas pipelines on the basis
of price (in terms of transportation fees), quality of customer service and
operational flexibility. Competition for natural gas storage is
primarily based on location and the ability to deliver natural gas in a timely
and reliable manner. Our natural gas storage facilities compete with
other providers of natural gas storage, including other salt dome storage
facilities and depleted reservoir facilities. Our natural gas
marketing activities compete primarily with other natural gas pipeline companies
and their marketing affiliates and financial institutions with trading
platforms. Competition in the natural gas marketing business is based
primarily on quality of customer service, competitive pricing and proximity to
customers and other market hubs.
Properties. The following table
summarizes the significant assets included in our Natural Gas Pipelines &
Services business segment at February 1, 2010:
|
Approx.
Net
|
|||||
|
Capacity,
|
Working
|
||||
|
Length
|
Natural
Gas
|
Capacity
|
|||
|
Description
of Asset
|
Location
|
(Miles)
|
(MMcf/d)
|
(Bcf)
|
|
|
Natural
gas pipelines:
|
|||||
|
Texas
Intrastate System
|
Texas
|
8,051
|
6,640
|
||
|
Acadian
Gas System
|
Louisiana
|
1,041
|
1,149
|
||
|
Big
Thicket Gathering System (1)
|
Texas
|
262
|
60
|
||
|
Canales
Gathering System
|
Texas
|
32
|
75
|
||
|
Total
miles
|
9,386
|
||||
|
Natural
gas storage facilities:
|
|||||
|
Wilson (2)
|
Texas
|
6.8
|
|||
|
Acadian
(3)
|
Louisiana
|
1.3
|
|||
|
Total
gross capacity
|
8.1
|
||||
|
(1)
The
Big Thicket Gathering System is an integral part of our NGL marketing
activities, the results of operations of which are accounted for under our
NGL Pipelines & Services business segment.
(2)
This
facility is held under an operating lease that expires in January
2028.
(3)
This
facility is held under an operating lease that expires in December
2012.
|
|||||
On a weighted-average basis, aggregate
utilization rates for our natural gas pipelines were approximately 62.5%, 68.3%
and 63.3% during the years ended December 31, 2009, 2008 and 2007,
respectively.
The following information highlights
the general use of each of our principal natural gas pipelines, all of which we
operate except for small segments of the Texas Intrastate System.
|
§
|
The
Texas Intrastate
System gathers and transports natural gas from supply basins in
Texas (from both onshore and offshore sources) to local gas distribution
companies and electric generation and industrial and municipal consumers
as well as to connections with intrastate and interstate
pipelines. The Texas Intrastate System is comprised of the
6,560-mile Enterprise Texas pipeline system, the 641-mile Channel pipeline
system, the 660-mile Waha gathering system and the 190-mile TPC Offshore
gathering system. The Enterprise Texas pipeline system includes
a 263-mile pipeline we lease from an affiliate of ETP. The
leased Wilson natural gas storage facility, located in Wharton County,
Texas, is an integral part of the Texas Intrastate
System. Collectively, the Texas Intrastate System serves
important natural gas producing regions and commercial markets in Texas,
including Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange
area and the Houston area, including the Houston Ship Channel industrial
market.
|
The
173-mile Sherman Extension pipeline, which is part of our Texas Intrastate
System, was completed in February 2009 and is capable of transporting up to 1.2
Bcf/d of natural gas from the prolific Barnett Shale production basin in north
Texas. The Sherman Extension provides producers
with connections to third-party interstate pipelines having access to markets
outside of Texas. An aggregate of 1.0 Bcf/d of the Sherman
Extension’s throughput capacity has been contracted by customers, including EPO,
under long-term contracts.
In late
2008, we began design of the 40-mile Trinity River Lateral, which is expected to
be completed during the second quarter of 2010. The Trinity River
Lateral will be capable of transporting up to 1.0 Bcf/d of natural gas and will
provide producers in the Barnett Shale production basin with additional takeaway
capacity. We are also constructing a new storage cavern adjacent to
the leased Wilson natural gas storage facility that is expected to be completed
in 2010. When completed, this new cavern is expected to provide us
with an additional 5.0 Bcf of useable natural gas storage capacity.
As a
result of the DEP II drop down transaction, we own a 51% equity interest in the
entity that owns the Enterprise Texas and Channel pipeline systems and leases
the Wilson storage facility. In addition, we own a 66% equity
interest in the entity that owns the Waha and TPC Offshore gathering
systems. EPO owns the remaining equity interests in these
entities.
|
§
|
The
Acadian Gas
System purchases, transports, stores and resells natural gas in
Louisiana. The Acadian Gas System is comprised of the 576-mile
Cypress pipeline, the 438-mile Acadian pipeline and the 27-mile Evangeline
pipeline. The leased Acadian natural gas storage facility at
Napoleonville, Louisiana is an integral part of the Acadian Gas
System. The Acadian Gas pipeline system links natural gas
supplies from onshore Gulf Coast and offshore Gulf of Mexico developments
with local gas distribution companies, electric generation plants and
industrial customers, located primarily in the natural gas market area of
the Baton Rouge – New Orleans – Mississippi River
corridor.
|
In
October 2009, we and EPO announced plans to build the Haynesville
Extension. As currently designed, our Haynesville Extension pipeline
will have the capacity to transport up to 2.1 Bcf/d of natural gas from the
Haynesville region through a 249-mile pipeline that will connect with our
existing Acadian Gas System. The pipeline is expected to be placed
into service during the third quarter of 2011.
As a
result of the DEP I drop down transaction, we own a 66% equity interest in the
entities that own the Acadian Gas System, including a 49.51% interest in the
Evangeline pipeline, discussed below.
Evangeline’s
most significant contract is a natural gas sales agreement with Entergy
Louisiana (“Entergy”) that expires in January 2013. Under this
contract, Evangeline is obligated to make available-for-sale and deliver to
Entergy certain specified minimum contract quantities of natural gas on an
hourly, daily, monthly and annual basis. The sales contract provides
for minimum annual quantities of 36.8 BBtus of natural gas.
In
connection with the Entergy sales contract, Evangeline has entered into a
natural gas purchase agreement with a subsidiary of Acadian Gas that contains
annual purchase provisions. The pricing terms of Evangeline’s sales
contract with Entergy and its purchase agreement with a subsidiary of Acadian
Gas are based on a monthly weighted-average market price of natural gas (subject
to certain market index price ceilings and incentive margins) plus a
predetermined margin. Our natural gas sales to Evangeline totaled
$155.5 million, $362.9 million and $264.2 million for the years ended December
31, 2009, 2008 and 2007, respectively. The amount of natural gas
purchased by Evangeline pursuant to this contract averaged approximately 50
BBtus/d during each of the years ended December 31, 2009, 2008 and 2007,
respectively.
NGL
Pipelines & Services
Our NGL Pipelines & Services
business segment includes our NGL and related product storage facility located
at Mont Belvieu, Texas and our South Texas NGL Pipeline System that connects our
Mont Belvieu storage complex to midstream energy infrastructure located in south
Texas. In addition, this segment includes two NGL fractionators
located in south Texas and the results of NGL marketing activities related to
our Big Thicket Gathering System.
NGL products (ethane, propane, normal
butane, isobutane and natural gasoline) are used as raw materials by the
petrochemical industry, as feedstocks by refiners in the production of motor
gasoline and by industrial and residential users as fuel. Ethane is
primarily used in the petrochemical industry as a feedstock for ethylene
production, one of the basic building blocks for a wide range of plastics and
other chemical products. Propane is used both as a petrochemical
feedstock in the production of ethylene and propylene and as heating, engine and
industrial fuel. Normal butane is used as a petrochemical feedstock
in the production of ethylene and butadiene (a key ingredient of synthetic
rubber), as a blendstock for motor gasoline and to produce isobutane through
isomerization. Isobutane is fractionated from mixed butane (a mixed
stream of normal butane and isobutane) or produced from normal butane through
the process of isomerization, and is used in refinery alkylation to enhance the
octane content of motor gasoline, in the production of isooctane and other
octane additives, 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 or as a petrochemical feedstock.
NGL and
related product storage facilities. Our NGL
and petrochemical storage facilities receive, store and deliver NGLs and
petrochemical products for industrial customers located along the Texas Gulf
Coast. This area has the largest concentration of petrochemical
plants and refineries in the United States. Our NGL and petrochemical
storage facilities are interconnected by multiple pipelines to other producing
and offtake facilities throughout the Gulf Coast region, including EPO’s NGL
import and export facility located on the Houston Ship Channel, as well as
connections to the Rocky Mountain and Midwest regions via EPO’s Seminole
pipeline, to Louisiana via EPO’s Lou-Tex NGL pipeline and to east Texas via
EPO’s Panola pipeline.
We also store certain petrochemicals
such as propylene (chemical, polymer and refinery grades) and
ethylene. Chemical-grade propylene is a petrochemical used in
plastics, synthetic fibers and foams. Polymer-grade propylene is
primarily used in the manufacture of polypropylene, which has a variety of end
uses, including packaging film, carpet and upholstery fibers and plastic parts
for appliances, automobiles and medical devices. Refinery grade
propylene is produced by refineries and is used as a feedstock in the production
of polymer-grade and chemical-grade propylene. Ethylene is also a key
building block for the petrochemical industry. Ethylene derivatives
are used in film applications for packaging, carrier bags and trash
liners. Other applications include injection molding, pipe extrusion
and cable sheathing and insulation, as well as extrusion coating of paper and
cardboard.
Under our NGL and petrochemical storage
agreements, we charge customers monthly storage reservation fees to reserve
storage capacity in our underground caverns. Our customers pay
reservation fees based on the level of storage capacity reserved rather than the
actual volumes stored. When a customer exceeds its reserved capacity,
we charge those customers an excess storage fee. In addition, we
charge customers throughput fees based on volumes placed into and withdrawn from
storage. Lastly, brine production revenues are derived from customers
that use brine in the production of chlorine and caustic soda, which is used in
the production of polyvinyl chloride (“PVC”) and for industrial products used in
crude oil production and fractionation. Brine is produced by placing
fresh water into a well to create cavern space within the salt
dome. This process creates brine for our customers and develops new
underground wells for product storage. Accordingly, the profitability
of our storage operations is dependent upon the level of storage capacity
reserved by customers, the volume of product placed into and withdrawn from the
underground caverns, the level of fees charged and the volume of brine produced
for customers.
We have a
broad range of customers for our storage services with contract terms that vary
from month-to-month to long-term contracts with durations of one to ten
years. We currently offer our customers, in various quantities and at
varying terms, two main types of storage contracts: multi-product fungible
storage and segregated product storage. Multi-product fungible
storage allows customers to store any combination of fungible
products. Segregated product storage allows customers to store
non-fungible products such as propylene, ethylene and
naphtha. Segregated storage allows a customer to reserve an entire
storage cavern and have its own product injected and withdrawn without having
its product commingled. We evaluate pricing, volume and availability
for storage on a case-by-case basis.
Storage well measurement gains and
losses occur when underground storage wells are physically
emptied. Storage well gains and losses are a result of volumetric
measurement differences on aggregate volumes of product injected into a storage
well and the aggregate volumes withdrawn from storage. In connection
with storage agreements entered into between EPO and Mont Belvieu Caverns,
effective concurrently with the closing of our initial public offering, EPO
agreed to assume all storage well measurement gains and losses.
Operational measurement gains and
losses are created when product is moved between storage wells and are
attributable to pipeline and well connection measurement
variances. The Mont Belvieu Caverns’ limited liability company
agreement allocates to EPO any items of income or loss relating to net
operational measurement gains and losses, including amounts that Mont Belvieu
Caverns may retain as handling losses. As such, EPO is required each
period to contribute cash to Mont Belvieu Caverns for net operational
measurement losses and is entitled to receive distributions from Mont Belvieu
Caverns for net operational measurement gains. We continue to record
operational measurement gains and losses associated with our Mont Belvieu
storage complex as a component of operating costs and
expenses. However, these operational measurement gains and losses
should not affect our net income attributable to Duncan Energy Partners or have
a significant impact on us with respect to the timing of our net cash flows
provided by operating activities and, accordingly, we have not established a
reserve for operational measurement losses on our balance sheet. We
recognized net operational measurement losses of $1.7 million and $6.8 million
for the years ended December 31, 2009 and 2008, respectively, and a net
operational measurement gain of $4.5 million for the year ended December 31,
2007, which were allocated to EPO.
NGL
pipelines and related marketing activities. Our NGL
pipelines (i) transport mixed NGLs from natural gas processing facilities and
refineries to NGL fractionation plants and storage facilities and (ii)
distribute to, and collect purity NGL products from, petrochemical plants and
refineries. Revenues from our NGL pipeline transportation agreements
are generally based upon a fixed fee per gallon of liquids transported
multiplied by the volume delivered. Accordingly, the results of
operations for this business are generally dependent upon the volume of product
transported and the level of fees charged to customers. The
transportation fees charged under these arrangements are contractual and not
typically regulated by governmental agencies. Typically, we do not
take title to the products transported in our NGL pipelines; rather, the shipper
retains title and the associated commodity price risk.
The NGL marketing activities of our Big
Thicket Gathering System generate revenues from the sale and delivery of NGLs
obtained through natural gas processing agreements at EPO’s Indian Springs
natural gas processing plant located in east Texas. The results of
operations from our NGL marketing activities are generally dependent upon the
volume of products sold and the market-based sales prices charged to
customers. EPO is the primary customer of our NGL marketing
activities.
NGL
fractionation. Our
Shoup and Armstrong NGL fractionators process mixed NGLs supplied by EPO’s south
Texas natural processing plants. Revenues from our NGL fractionators
are generally based on fee-based arrangements for our NGL fractionation
services. These arrangements typically include a base-processing fee
(usually stated in cents per gallon) that is contractually subject to adjustment
for changes in certain fractionation expenses, including natural gas fuel
costs. Purity NGL products from the Shoup and Armstrong fractionators
are transported to Mont Belvieu, Texas using our South Texas NGL
System.
Based on
industry data, we believe that there will be sufficient quantities of natural
gas in south Texas to support the production of mixed NGLs for more than twenty
years. For example, exploration and production activity has increased
in the emerging Eagle Ford Shale, which is believed to cover more than 10
million acres in southern Texas. Certain natural gas production from
this region is rich in NGLs that must be removed before the natural gas can meet
quality specifications to be transported in downstream natural gas
pipelines. In the mid-Gulf Coast region, rich Wilcox gas is found at
depths in the 10,000 to 15,000 feet range. Shale gas in these areas
may also have high NGL content. We expect that ongoing natural gas
exploration and production activities will result in new volumes that will
mitigate the effects of normal depletion rates of existing resource
basins.
Seasonality. Our NGL
fractionation and pipeline operations typically exhibit little to no seasonal
variation. With respect to our NGL and related product storage
facilities, we usually experience an increase in demand for storage services
during the spring and summer months due to increased feedstock storage
requirements for motor gasoline production and a decrease during the fall and
winter months when propane inventories are being drawn down for heating
needs. Our facilities located along the Gulf Coast may also be
affected by weather events such as hurricanes and tropical storms, which
generally arise during the summer and fall months.
Competition. Our
competitors in the NGL and related product storage business are integrated major
oil companies, chemical companies and other storage and pipeline
companies. With respect to our Mont Belvieu underground storage
complex, we primarily compete against LDH Energy Mont Belvieu L.P., Targa
Resources, Inc. and ONEOK Partners, L.P. We compete with other
storage service providers primarily in terms of the fees charged, number of
pipeline connections and operational dependability. We believe that
the fees we charge our storage customers are competitive with those charged by
other storage operators because we have historically been able to renew existing
contracts as they mature, resulting in many long-standing customer
relationships. We also believe that the number of pipelines connected
to our storage facilities allows us to offer customers a wider variety of
receipt and delivery options with respect to key Gulf Coast petrochemical
plants, NGL fractionators and other users of the products we
store. Furthermore, we believe that our emphasis on maintenance and
safety provides our customers with a high level of confidence in our operational
dependability.
Our south Texas NGL pipelines and
fractionators are not affected by competition given that EPO is the primary
customer of these businesses.
Properties. The following table
summarizes the significant assets included in our NGL Pipelines & Services
business segment at February 1, 2010:
|
Useable
|
Total
|
||||
|
Storage
|
Plant
|
||||
|
Length
|
Capacity
|
Capacity
|
|||
|
Description
of Asset
|
Location
|
(Miles)
|
(MMBbls)
|
(MBPD)
|
|
|
NGL
pipelines:
|
|||||
|
South
Texas NGL Pipeline System
|
Texas
|
1,317
|
|||
|
NGL
and petrochemical storage facilities:
|
|||||
|
Mont
Belvieu Storage (34 caverns) (1)
|
Texas
|
103.5
|
|||
|
Almeda
(6 caverns) (1, 2)
|
Texas
|
13.4
|
|||
|
Markham
(2 caverns) (1, 2)
|
Texas
|
4.3
|
|||
|
Total
useable capacity
|
121.2
|
||||
|
NGL
fractionation facilities:
|
|||||
|
Shoup
|
Texas
|
69
|
|||
|
Armstrong
|
Texas
|
13
|
|||
|
Total
plant capacities
|
82
|
||||
|
(1)
The
Mont Belvieu storage complex includes above-ground brine pit capacity of
20 MMBbls. Brine capacity at the Almeda and Markham facilities
is limited to the quantity necessary to support the product storage
operations.
(2)
Our
interest in these facilities is held under long-term operating
leases.
|
|||||
The maximum number of barrels that our
South Texas NGL Pipeline System can transport per day depends upon the operating
balance achieved at a given point in time between various segments of this
system. Since the operating balance is dependent upon the mix of
products being shipped and demand levels at various delivery points, the exact
capacities of such pipelines cannot be reliably determined. We
measure the utilization rate of our South Texas NGL Pipeline System in terms of
average throughput. Total average throughput volume for this pipeline
was 109 MBPD, 126 MBPD and 124 MBPD during the years ended December 31, 2009,
2008 and 2007, respectively.
On a weighted-average basis, aggregate
utilization rates for our NGL fractionation plants were approximately 86.8%,
84.3% and 82.8% during the years ended December 31, 2009, 2008 and 2007,
respectively.
The following information highlights
the general use of each of our principal NGL pipeline, storage and fractionation
assets, all of which we operate except for the leased Markham and Almeda NGL
storage facilities.
|
§
|
The
Mont Belvieu
Storage complex consists of three interconnected underground
storage facilities: Mont Belvieu East, Mont Belvieu West and
Mont Belvieu North. The Mont Belvieu East facility is the largest of
our three Mont Belvieu storage facilities. This facility
consists of 14 underground salt dome storage caverns with a storage
capacity of approximately 56 MMBbls and an above-ground brine pit
with a brine capacity of approximately 10 MMBbls. This
facility also has two brine production wells. The Mont Belvieu
West facility consists of 10 underground salt dome storage caverns with a
storage capacity of approximately 15 MMBbls and an above-ground brine
pit with a brine capacity of approximately 2 MMBbls. The
Mont Belvieu North facility consists of 10 underground salt dome storage
caverns with a storage capacity of approximately 30 MMBbls and an
above-ground brine pit with a brine capacity of approximately
8 MMBbls.
|
Our
storage customers include a broad range of NGL and petrochemical producers and
consumers, including many of the largest petrochemical facilities and refineries
in the Texas and Louisiana Gulf Coast region. Our three largest
third-party storage customers, which accounted for a combined 20.5% of our
segment revenues for the year ended December 31, 2009, were affiliates of Exxon
Mobil, Dow Chemical Company and Chevron Corporation.
We also
provide underground storage services to EPO, which accounted for 34.0% of our
Mont Belvieu storage revenues for the year ended December 31,
2009.
As a
result of the DEP I drop down transaction, we own a 66% equity interest Mont
Belvieu Caverns. EPO owns the remaining equity interests in this
entity.
|
§
|
The
South Texas NGL Pipeline
System consists of (i) approximately 380 miles of intrastate NGL
transportation pipelines that transport mixed NGLs from various south
Texas natural gas processing facilities (primarily those owned by EPO) to
our Shoup and Armstrong fractionators and (ii) intrastate NGL pipelines
aggregating 937 miles that deliver NGLs from the Shoup and Armstrong
fractionators to our Mont Belvieu storage complex and to other customers
along the upper Texas Gulf Coast. The leased Markham and Almeda
NGL storage facilities are integral components of the South Texas NGL
System.
|
The Shoup NGL fractionator is
located in Corpus Christi, Texas and receives mixed NGLs from six natural gas
processing plants located in south Texas. The Armstrong NGL fractionator is
located in DeWitt County, Texas and fractionates mixed NGLs for EPO’s Armstrong
natural gas processing plant.
A major
customer of our South Texas NGL Pipeline System and Shoup and Armstrong NGL
fractionators is EPO. EPO accounted for 82.6% of revenues generated
by these assets during the year ended December 31, 2009.
As a
result of the DEP I and DEP II drop down transactions, we own a 66% equity
interest in the entities that own the South Texas NGL Pipeline System and Shoup
and Armstrong fractionators. EPO owns the remaining equity interests
in these entities.
Petrochemical
Services
Our Petrochemical Services business
segment reflects the operations of our Lou-Tex Propylene Pipeline and Sabine
Propylene Pipeline. These pipelines provide for the transportation of
polymer-grade and chemical-grade propylene in Texas and
Louisiana. Polymer-grade propylene is used in the manufacture of
polypropylene. Chemical-grade propylene is a basic petrochemical used
in plastics, synthetic fibers and foams.
The following information highlights
the general use of our Lou-Tex Propylene and Sabine Propylene pipelines, both of
which we operate:
|
§
|
The
Lou-Tex Propylene
Pipeline is a 263-mile pipeline used to transport chemical-grade
propylene from Sorrento, Louisiana to Mont Belvieu,
Texas. Shell Oil Company (“Shell”) and Exxon Mobil are the only
customers of this pipeline. The chemical-grade propylene we
transport for Shell originates at its underground storage facility located
in Sorrento, Louisiana and is delivered to various receipt points between
Sorrento, Louisiana and Mont Belvieu, Texas. The chemical-grade
propylene we transport for Exxon Mobil originates from its refining and
chemical complex located in Baton Rouge, Louisiana and is delivered to
either Exxon Mobil’s customers or to an underground storage well located
in Mont Belvieu, Texas owned by Mont Belvieu
Caverns.
|
|
§
|
The
Sabine Propylene
Pipeline consists of a 21-mile pipeline used to transport
polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect
in Cameron Parish, Louisiana. Shell is the sole customer of
this pipeline. The polymer-grade propylene transported for
Shell originates from the TOTAL/BASF Port Arthur cracker facility and is
delivered to the Lyondell Basell polypropylene facility in Lake Charles,
Louisiana.
|
|
|
As
a result of the DEP I drop down transaction, we own a 66% equity interest
in Lou-Tex Propylene and Sabine Propylene. EPO owns the
remaining equity interests in these
entities.
|
Revenues recorded for the Lou-Tex
Propylene Pipeline and Sabine Propylene Pipeline are primarily based on exchange
agreements with Shell and Exxon Mobil. As a result of these exchange
agreements, we agree to receive propylene in one location and deliver propylene
at another location for a
fee. The
following information summarizes the exchange agreements with Shell and Exxon
Mobil:
|
§
|
Shell
Exchange Agreements – Shell is obligated to meet minimum delivery
requirements under the Lou-Tex Propylene and Sabine Propylene
agreements. If Shell fails to meet such minimum delivery
requirements, it is obligated to pay a deficiency fee to
us. The term of the Lou-Tex Propylene exchange agreement
expires in March 2020 and the term of the Sabine Propylene exchange
agreement expires in November 2011. The Lou-Tex exchange
agreement will continue on a year-to-year basis after expiration, subject
to termination by either party. The fees paid by Shell under
the Lou-Tex Propylene exchange agreement are generally fixed and are
adjusted annually based on the operating costs of the pipeline and the
U.S. Department of Labor wage index. During 2009, Shell
provided notice of its intent to terminate the Sabine Propylene exchange
agreement in November 2011. Given the importance of the Sabine
Propylene Pipeline in delivering feedstocks to facilities connected to
this pipeline, we believe that the Sabine Propylene Pipeline will remain
commercially viable after the Shell exchange agreement expires in
2011.
|
|
§
|
Exxon
Mobil Exchange Agreement – The term of the Lou-Tex Propylene Pipeline
exchange agreement expired in June 2008, but continues on a monthly
basis subject to a two-year termination notice initiated by either
party. The exchange fees paid by Exxon Mobil are based on the
volume of chemical-grade propylene
delivered.
|
Our propylene transportation business
exhibits little seasonality. With respect to competition, our
petrochemical pipelines are in single product service due to the required purity
of the product being shipped. Because there are no other pipelines in
our market area which ship the same dedicated purity-grade product, competition
for this service is limited. In the future, a competitor could change
service of an existing pipeline to ship such purity products, but would incur
additional costs to connect their systems to our customers.
The maximum number of barrels that our
petrochemical pipelines can transport per day depends upon the operating balance
achieved at a given point in time between various segments of the
system. Since the operating balance is dependent upon the demand
levels at various delivery points, the exact capacity of our petrochemical
pipelines cannot be reliably determined. We measure the utilization
rates of our petrochemical pipelines in terms of average
throughput. Total average throughput volumes for these pipelines were
30 MBPD, 35 MBPD and 37 MBPD during the years ended December 31, 2009, 2008 and
2007, respectively.
Title
to Properties
Our real property holdings fall into
two basic categories: (1) parcels that we own in fee, such as the land and
underlying storage caverns at Mont Belvieu, Texas and (2) parcels in which
our interest derives from leases, easements, rights-of-way, permits or licenses
from landowners or governmental authorities permitting the use of such land for
our operations. The fee sites upon which our significant facilities
are located have been owned by us or our predecessors in title for many years
without any material challenge known to us relating to title to the land upon
which the assets are located, and we believe that we have satisfactory title to
such fee sites. We have no knowledge of any challenge to the
underlying fee title of any material lease, easement, right-of-way, permit or
license held by us or to our rights pursuant to any material lease, easement,
right-of-way, permit or license. We believe that we have satisfactory
rights pursuant to all of our material leases, easements, rights-of-way, permits
and licenses.
Capital
Spending
For a discussion of our capital
spending programs, see “Liquidity and Capital Resources” included under Item 7
of this annual report.
Regulation
Interstate
Pipelines
Liquids
Pipelines. The Lou-Tex Propylene and Sabine Propylene
pipelines are interstate common carrier pipelines regulated under the Interstate
Commerce Act (“ICA”) by the Surface Transportation Board (“STB”). If
the STB finds that a carrier’s rates are not just and reasonable or are unduly
discriminatory or preferential, it may prescribe a reasonable
rate. In determining a reasonable rate, the STB will consider, among
other factors, the effect of the rate on the volumes transported by that
carrier, the carrier’s revenue needs and the availability of other economic
transportation alternatives.
The STB does not need to provide rate
relief unless shippers lack effective competitive alternatives. If
the STB determines that effective competitive alternatives are not available and
a pipeline holds market power, then we may be required to show that our rates
are reasonable.
Intrastate
Pipelines
Liquids
Pipelines. Certain of our
pipeline systems operate within a single state and provide intrastate pipeline
transportation services. These pipeline systems are subject to
various regulations and statutes mandated by state regulatory
authorities. Although the applicable state statutes and regulations
vary widely, they generally require that intrastate pipelines publish tariffs
setting forth all rates, rules and regulations applying to intrastate service,
and generally require that pipeline rates and practices be reasonable and
nondiscriminatory. Shippers may challenge our intrastate tariff rates
and practices on our pipelines. Our intrastate liquids pipelines are
subject to regulation in Texas.
Natural
Gas Pipelines. Our intrastate natural gas pipelines are
subject to regulation in Louisiana and Texas. Certain of our
intrastate natural gas pipelines are also subject to limited regulation by the
Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Policy Act
of 1978 (“NGPA”) because they provide transportation and storage service
pursuant to Section 311 of the NGPA and Part 284 of the FERC’s
regulations. Under Section 311 of the NGPA, an intrastate pipeline
may transport gas on behalf of an interstate pipeline company or any local
distribution company served by an interstate pipeline without becoming subject
to the FERC’s jurisdiction under the Natural Gas Act of 1938
(“NGA”). However, such a pipeline is required to provide these
services on an open and nondiscriminatory basis, and to make certain rate and
other filings and reports in compliance with the FERC’s
regulations. The rates for 311 services may be established by the
FERC or the respective state agency, but such rates may not exceed a fair and
equitable rate.
In September 2007, the FERC approved an
uncontested settlement establishing our maximum firm and interruptible
transportation rates for NGPA Section 311 service on the Enterprise Texas
Pipeline. In June and July 2008, we filed to amend our Statement of
Operating Conditions (“SOC”) for our transportation and storage services,
respectively. In September 2008, we submitted to the FERC a new
proposed Section 311 rate for service on our Sherman Extension
pipeline. On November 23, 2009, we filed an uncontested settlement
agreement, which, if approved, would resolve the Sherman Extension rate issues.
The other issues related to the SOC are reserved under the settlement agreement
for a decision by the FERC based on the pleadings. Under the
settlement agreement that resulted from the September 2007 proceeding, we are
required to file another rate petition on or before April 2010 to justify our
current rates or establish new rates for the NGPA Section 311 service on the
remainder of the system. The FERC has not acted upon the settlement
agreement. The Texas Railroad Commission has the authority to
regulate the rates and terms of service for our intrastate transportation
service in Texas.
In July 2009, we filed with the FERC
proposed changes to our SOC and to increase our interruptible transportation
rates for NGPA Section 311 service for the Acadian and Cypress pipelines, which
are part of our Acadian Gas System. On December 8, 2009, the FERC
issued an order extending its review period to encourage settlement
discussions. Settlement negotiations are on-going.
Sales
of Natural Gas
We are engaged in natural gas marketing
activities. The resale of natural gas in interstate commerce is
subject to FERC jurisdiction. However, under current federal rules
the price at which we sell natural gas is not regulated insofar as the
interstate market is concerned and, for the most part, is not subject to state
regulation. Our affiliates that engage in natural gas marketing are
considered marketing affiliates of certain of EPO’s interstate natural gas
pipelines. The FERC’s rules require pipelines and their marketing
affiliates who sell natural gas in interstate commerce subject to the FERC’s
jurisdiction to adhere to standards of conduct that, among other things, require
that their transportation and marketing employees function independently of
each other. Pursuant to the Energy Policy Act of 2005, the FERC has
also established rules prohibiting energy market manipulation. A
violation of these rules by us or our employees or agents may subject us to
civil penalties, suspension or loss of authorization to perform such sales,
disgorgement of unjust profits or other appropriate non-monetary remedies
imposed by the FERC. The Federal Trade Commission and the Commodity
Futures Trading Commission also have issued rules and regulations prohibiting
market manipulation.
The FERC
is continually proposing and implementing new rules and regulations affecting
segments of the natural gas industry. For example, the FERC has
adopted new market monitoring and annual reporting regulations which are
applicable to many intrastate pipelines and other entities that are otherwise
not subject to FERC’s NGA jurisdiction. The FERC also has established
rules requiring certain non-interstate pipelines to post daily scheduled volume
information and design capacity for certain points, and has also required the
annual reporting of gas sales information, in order to increase transparency in
natural gas markets. Non-interstate service providers, which include
NGPA Section 311 service providers, are required to begin posting the
information by June 30, 2010. We cannot predict the ultimate impact
of these regulatory changes on our natural gas marketing activities; however, we
believe that any new regulations will also be applied to other natural gas
marketers with whom we compete.
For
additional information regarding the potential impact of federal, state or local
regulatory measures on our business, please read Item 1A “Risk Factors” of this
annual report.
Environmental
and Safety Matters
Our pipelines and other facilities are
subject to multiple environmental obligations and potential liabilities under a
variety of federal, state and local laws and regulations. These
include, without limitation: the Comprehensive Environmental Response,
Compensation, and Liability Act (“CERCLA”); the Resource Conservation and
Recovery Act (“RCRA”); the Federal Clean Air Act (“CAA”); the Federal Water
Pollution Control Act of 1972, renamed and amended as the Clean Water Act
(“CWA”); the Oil Pollution Act of 1990 (“OPA”); and analogous state and local
laws and regulations. Such laws and regulations affect many aspects
of our present and future operations, and generally require us to obtain and
comply with a wide variety of environmental registrations, licenses, permits,
inspections and other approvals, with respect to air emissions, water quality,
wastewater discharges and solid and hazardous waste
management. Failure to comply with these requirements may expose us
to fines, penalties and/or interruptions in our operations that could influence
our financial position, results of operations and cash flows. If an
accidental leak, spill or release of hazardous substances occurs at any
facilities that we own, operate or otherwise use, or where we send materials for
treatment or disposal, we could be held jointly and severally liable for all
resulting liabilities, including investigation, remedial and clean-up
costs. Likewise, we could be required to remove or remediate
previously disposed wastes or property contamination, including groundwater
contamination. Any or all of this could materially affect our
financial position, results of operations and cash flows.
We believe our operations are in
material compliance with applicable environmental and safety laws and
regulations, and that compliance with existing environmental and safety laws and
regulations are not expected to have a material adverse effect on our financial
position, results of operations and cash flows. Environmental and
safety laws and regulations are subject to change. The clear trend in
environmental regulation is to place more restrictions and limitations on
activities that may be perceived to affect the environment, and thus there can
be no assurance as to the amount or timing of future expenditures for
environmental regulation compliance or remediation, and actual future
expenditures may
be
different from the amounts we currently anticipate. Revised or additional
regulations that result in increased compliance costs or additional operating
restrictions, particularly if those costs are not fully recoverable from our
customers, could have a material adverse effect on our business, financial
position, results of operations and cash flows. Below is a discussion
of the material environmental laws and regulations that relate to our
business.
Air
Emissions
Our operations are subject to the CAA
and comparable state laws and regulations. These laws and regulations
regulate emissions of air pollutants from various industrial sources, including
our facilities, and also impose various monitoring and reporting requirements.
Such laws and regulations may require that we obtain pre-approval for the
construction or modification of certain projects or facilities expected to
produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and
operational limitations, or utilize specific emission control technologies to
limit emissions.
Our permits and related compliance
under the CAA, as well as recent or soon to be adopted changes to state
implementation plans for controlling air emissions in regional, non-attainment
areas, may require our operations to incur future capital expenditures in
connection with the addition or modification of existing air emission control
equipment and strategies. In addition, some of our facilities are
included within the categories of hazardous air pollutant sources, which are
subject to increasing regulation under the CAA. Our failure to comply
with these requirements could subject us to monetary penalties, injunctions,
conditions or restrictions on operations, and enforcement actions. We
may be required to incur certain capital expenditures in the future for air
pollution control equipment in connection with obtaining and maintaining
operating permits and approvals for air emissions. We believe,
however, that such requirements will not have a material adverse effect on our
operations, and the requirements are not expected to be any more burdensome to
us than any other similarly situated company.
In response to certain scientific
studies suggesting that emissions of certain gases, commonly referred to as
“greenhouse gases” and including carbon dioxide and methane, are contributing to
the warming of the Earth’s atmosphere and other climatic changes, the U.S.
Congress has been actively considering legislation to reduce such
emissions. On June 26, 2009, the U.S. House of Representatives passed
the American Clean Energy and Security Act of 2009 (“ACESA”), which would
establish an economy-wide cap-and-trade program intended 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 percent reduction in greenhouse gas
emissions from 2005 levels by 2020 and just over an 80 percent reduction of such
emissions by 2050. Under this legislation, the Environmental
Protection Agency (“EPA”) would issue a capped and steadily declining number of
tradable emissions allowances to major sources of greenhouse gas emissions so
that such sources could continue to emit greenhouse gases into the
atmosphere. The costs of these allowances would be expected to
escalate significantly 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 or other hydrocarbon
products that we transport, store or otherwise handle in connection with our
midstream services.
In addition, on December 7, 2009, the
EPA announced its finding that emissions of greenhouse gases presented an
endangerment to human health and the environment. These findings by
the EPA allow the agency to proceed with the adoption and implementation of
regulations that would restrict emissions of greenhouse gases under existing
provisions of the CAA. In late September 2009, the EPA had proposed
two sets of regulations in anticipation of finalizing its endangerment finding
that would require a reduction in emissions of greenhouse gases from motor
vehicles and, also, could trigger permit review for greenhouse gas emissions
from certain stationary sources. In addition, on September 22, 2009,
the EPA issued a final
rule
requiring the reporting of greenhouse gas emissions from specified large
greenhouse gas emission sources in the United States beginning in 2011 for
emissions occurring in 2010.
The adoption and implementation of any
regulations imposing reporting obligations on, or limiting 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 or
could adversely affect demand for the natural gas or other hydrocarbon products
that we transport, store or otherwise handle in connection with our midstream
services. The potential increase in the costs of our operations could
include costs to operate and maintain our facilities, install new emission
controls on our facilities, acquire allowances to authorize our greenhouse gas
emissions, pay any taxes related to our greenhouse gas emissions and administer
and manage a greenhouse gas emissions program. While we may be able
to include some or all of such increased costs in the rates charged by our
pipelines or other facilities, such recovery of costs is uncertain and may
depend on events beyond our control, including the outcome of future rate
proceedings before the FERC and the provisions of any final
regulations.
Even if such legislation is not adopted
at the national level, more than one-third of the states have begun taking
actions to control and/or reduce emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission inventories and/or
regional greenhouse gas cap-and-trade programs. Although most of the
state-level initiatives have to date focused on large sources of greenhouse gas
emissions, such as coal-fired electric plants, it is possible that smaller
sources of emissions could become subject to greenhouse gas emission limitations
or allowance purchase requirements in the future. Any one of these
climate change regulatory and legislative initiatives could have a material
adverse effect on our business, financial position and results of
operations.
Other
Potential Impacts of Climate Change
Over the
last hundred years or so, certain instrumental temperature records have
evidenced a general increase in global mean temperature. As a result,
certain public advocacy groups attribute this rise to a phenomenon termed
“global warming.” Proponents of this theory argue that man-made
greenhouse gases have produced observable changes in the environment such as
shrinkage of the Arctic ice caps, releases of terrestrial carbon from permafrost
regions and increases in sea level. In addition, these individuals
believe that global warming will result in a continued increase in global
average temperatures over the course of this century, with a probable increase
in the frequency of extreme weather events, and changes in rainfall
patterns. Based on computer models promoted by these groups, certain
areas of the globe might benefit from such changes, while other areas would
experience costs. Severe global climate change could even result in
reduced diversity of ecosystems and the extinction of certain
species.
There is considerable debate in public
and private forums as to whether global warming is actually occurring and, if it
is, its consequences. However, if global warming is occurring, it
could have an impact on our operations. For example, our facilities
that are located in low lying areas such as the coastal regions of Louisiana may
be at increased risk due to flooding or more frequent and severe weather
events. Also, a reduction in the demand for hydrocarbon products that
are deemed to contribute to greenhouse gases may reduce volumes available to us
for fractionation, transportation, marketing and
storage. Unfortunately, there is currently no public consensus
regarding global warming, and the scientific community is divided on the
subject. We are providing this disclosure regarding the potential
physical effects of global warming based on publicly available information and
opinions on the matter. As a commercial enterprise, we are not in a
position to validate or repudiate the existence of global warming.
Water
The CWA and comparable state laws
impose strict controls on the discharge of oil and its derivatives into
navigable waters. The CWA provides penalties for any discharges of
petroleum products in reportable quantities and imposes substantial potential
liability for the costs of removing petroleum or other hazardous
substances. State laws for the control of water pollution also
provide varying civil and criminal penalties and liabilities in the case of a
release of petroleum or its derivatives in navigable waters or into
groundwater. Spill prevention control and countermeasure requirements
of federal laws require
appropriate
containment berms and similar structures to help prevent a petroleum tank
release from impacting navigable waters. The EPA has also adopted
regulations that require us to have permits in order to discharge certain storm
water run-off. Storm water discharge permits may also be required by
certain states in which we operate. These permits may require us to
monitor and sample the storm water run-off. The CWA and regulations
implemented thereunder further prohibit discharges of dredged and fill material
in wetlands and other waters of the United States unless authorized by an
appropriately issued permit. We believe that our costs of compliance
with these CWA requirements will not have a material adverse effect on our
operations.
The primary federal law for oil spill
liability is the OPA, which addresses three principal areas of oil pollution:
prevention, containment and cleanup and liability. OPA applies to
vessels, offshore platforms and onshore facilities, including terminals,
pipelines and transfer facilities. In order to handle, store or
transport oil, shore facilities are required to file oil spill response plans
with the United States Coast Guard, the United States Department of
Transportation Office of Pipeline Safety (“OPS”) or the EPA, as
appropriate. Numerous states have enacted laws similar to
OPA. Under OPA and similar state laws, responsible parties for a
regulated facility from which oil is discharged may be liable for removal costs
and natural resource damages. Any unpermitted release of petroleum or
other pollutants from our pipelines or facilities could result in fines or
penalties as well as significant remedial obligations.
Contamination resulting from spills or
releases of petroleum products is an inherent risk within the petroleum pipeline
industry. To the extent that groundwater contamination requiring
remediation exists along our pipeline systems as a result of past operations, we
believe any such contamination could be controlled or remedied without having a
material adverse effect on our financial position, but such costs are site
specific, and there is no assurance that the effect will not be material in the
aggregate.
Solid
Waste
In our normal operations, we generate
hazardous and non-hazardous solid wastes that are subject to requirements of the
federal RCRA and comparable state statutes, which impose detailed requirements
for the handling, storage, treatment and disposal of hazardous and solid
waste. We also utilize waste minimization and recycling processes to
reduce the volumes of our waste. Amendments to RCRA required the EPA
to promulgate regulations banning the land disposal of all hazardous wastes
unless the wastes meet certain treatment standards or the land-disposal method
meets certain waste containment criteria. In the past, although we
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons and other materials may have been disposed of or
released. In the future, we may be required to remove or remediate
these materials.
Environmental
Remediation
The CERCLA, also known as “Superfund,”
imposes liability, without regard to fault or the legality of the original act,
on certain classes of persons who contributed to the release of a “hazardous
substance” into the environment. These persons include the owner or operator of
a facility where a release occurred and companies that disposed or arranged for
the disposal of the hazardous substances found at a facility. Under CERCLA,
these persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies. CERCLA also authorizes the EPA and, in some
instances, third parties to take actions in response to threats to the public
health or the environment and to seek to recover the costs they incur from the
responsible classes of persons. It is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or other pollutants
released into the environment. In the course of our ordinary
operations, our pipeline systems generate wastes that may fall within CERCLA’s
definition of a “hazardous substance.” In the event a disposal
facility previously used by us requires clean up in the future, we may be
responsible under CERCLA for all or part of the costs required to clean up sites
at which such wastes have been disposed.
Pipeline
Safety Matters
We are
subject to regulation by the U.S. Department of Transportation (“DOT”) under the
Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to
as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state
statutes relating to the design, installation, testing, construction, operation,
replacement and management of our pipeline facilities. The HLPSA covers
petroleum and petroleum products and requires any entity that owns or operates
pipeline facilities to (i) comply with such regulations, (ii) permit access to
and copying of records, (iii) file certain reports, and (iv) provide information
as required by the Secretary of Transportation. We believe we are in
material compliance with these HLPSA regulations.
We are
also subject to the DOT regulation requiring qualification of pipeline
personnel. The regulation requires pipeline operators to develop and
maintain a written qualification program for individuals performing covered
tasks on pipeline facilities. The intent of this regulation is to
ensure a qualified work force and to reduce the probability and consequence of
incidents caused by human error. In addition, we are subject to a DOT regulation
that requires pipeline operators to institute certain control room
procedures. These procedures must be developed by August 1, 2011 and
implemented by February 2, 2012. The regulation establishes
qualification requirements for individuals performing covered
tasks. We believe we are in material compliance with these DOT
regulations.
In addition, we are subject to the DOT
Integrity Management regulations, which specify how companies should assess,
evaluate, validate and maintain the integrity of pipeline segments that, in the
event of a release, could impact High Consequence Areas
(“HCAs”). HCAs are defined to include populated areas, unusually
sensitive environmental areas and commercially navigable
waterways. The regulation requires the development and implementation
of an Integrity Management Program that utilizes internal pipeline inspection,
pressure testing, or other equally effective means to assess the integrity of
HCA pipeline segments. The regulation also requires periodic review
of HCA pipeline segments to ensure that adequate preventative and mitigative
measures exist and that companies take prompt action to address integrity issues
raised by the assessment and analysis. In June 2008, the DOT extended
its pipeline safety regulations, including Integrity Management requirements, to
certain rural onshore hazardous liquid gathering lines and certain rural onshore
low-stress hazardous liquid pipelines within a buffer area around “unusually
sensitive areas.” We have identified our HCA pipeline segments and
developed an appropriate Integrity Management Program.
Risk Management
Plans
We are
subject to the EPA’s Risk Management Plan regulations at certain
facilities. These regulations are intended to work with the
Occupational Safety and Health Act (“OSHA”) Process Safety Management (“PSM”)
regulations (see “Safety Matters” below) to minimize the offsite consequences of
catastrophic releases. The regulations require us to develop and
implement a risk management program that includes a five-year accident history,
an offsite consequence analysis process, a prevention program and an emergency
response program. We believe we are operating in material compliance
with our risk management program.
Safety
Matters
Certain
of our facilities are also subject to the requirements of the federal OSHA and
comparable state statutes. We believe we are in material compliance
with OSHA and state requirements, including general industry standards, record
keeping requirements and monitoring of occupational exposures.
We are subject to OSHA PSM regulations,
which are designed to prevent or minimize the consequences of catastrophic
releases of toxic, reactive, flammable or explosive chemicals. These
regulations apply to any process which involves a chemical at or above the
specified thresholds or any process which involves certain flammable liquid or
gas. We believe we are in material compliance with the OSHA PSM
regulations.
The OSHA
hazard communication standard, the EPA community right-to-know regulations under
Title III of the federal Superfund Amendment and Reauthorization Act and
comparable state statutes require us to organize and disclose information about
the hazardous materials used in our operations. Certain parts of this
information must be reported to federal, state and local governmental
authorities and local citizens upon request.
Employees
Like many publicly traded partnerships,
we have no employees. All of our management, administrative and
operating functions are performed by employees of EPCO pursuant to an
administrative services agreement (“ASA”) or by other service
providers. For additional information regarding the ASA, see
“Relationship with EPCO” in Note 15 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report. As of December 31, 2009,
there were approximately 1,900 EPCO personnel that spend all or a portion of
their time engaged in our business. Approximately 400 of these
individuals devote all of their time performing administrative, commercial and
operating duties for us. The remaining approximately 1,500 personnel
are part of EPCO’s shared service organization and spend all or a portion of
their time engaged in our business.
Available
Information
As a publicly traded partnership, we
electronically file certain documents with the U.S. Securities and Exchange
Commission (“SEC”). We file annual reports on Form 10-K; quarterly
reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along
with any related amendments and supplements thereto. From
time-to-time, we may also file registration statements and related documents in
connection with equity or debt offerings. You may read and copy any
materials we file with the SEC at the SEC’s Public Reference Room at 100 F
Street, NE, Washington, DC 20549. You may obtain information
regarding the Public Reference Room by calling the SEC at
1-800-SEC-0330. In addition, the SEC maintains an Internet website at
www.sec.gov
that contains reports and other information regarding registrants that file
electronically with the SEC.
We
provide electronic access to our periodic and current reports on our Internet
website, www.deplp.com. These
reports are available as soon as reasonably practicable after we electronically
file such materials with, or furnish such materials to, the SEC. You
may also contact our Investor Relations department at (866) 230-0745 for paper
copies of these reports free of charge. The Company does not intend
to incorporate the information on our website in this document.
An
investment in our common units involves certain risks. If any of
these risks were to occur, our business, financial position, results of
operations and cash flows could be materially adversely affected. In
that case, the trading price of our common units could decline, and you could
lose part or all of your investment.
The
following section lists the key current risk factors as of the date of this
filing that may have a direct and material impact on our business, financial
position, results of operations and cash flows.
Risks
Inherent in Our Business
Changes in demand
for and production of hydrocarbon products may materially adversely affect our
financial position, results of operations and cash flows.
We operate predominantly in the
midstream energy sector that includes transporting and storing natural gas, NGLs
and propylene. As such, our financial position, results of operations
and cash flows may be materially adversely affected by changes in the prices of
hydrocarbon products and by changes in the relative price levels among
hydrocarbon products. Changes in prices may impact demand for
hydrocarbon
products,
which in turn may impact production and volumes transported by us and related to
transportation and storage handling fees. We may also incur price
risk to the extent counterparties do not perform in connection with our
marketing of natural gas, NGLs and/or propylene.
Historically,
the price of natural gas has been extremely volatile, and we expect this
volatility to continue. The New York Mercantile Exchange (“NYMEX”)
daily settlement price for natural gas for the prompt month contract in 2008,
ranged from a high of $13.58 per MMBtu to a low of $5.29 per
MMBtu. In 2009, the NYMEX daily settlement price for natural gas
ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu.
Generally,
the prices of hydrocarbon products are subject to fluctuations in response to
changes in supply, demand, market uncertainty and a variety of additional
uncontrollable factors. These factors include:
|
§
|
the
level of domestic production and consumer product
demand;
|
|
§
|
the
availability of imported natural gas and actions taken by foreign oil and
natural gas providing nations;
|
|
§
|
the
availability of transportation systems with adequate
capacity;
|
|
§
|
the
availability of competitive fuels;
|
|
§
|
fluctuating
and seasonal demand for natural gas and
NGLs;
|
|
§
|
the
impact of conservation efforts;
|
|
§
|
the
extent of governmental regulation and taxation of production;
and
|
|
§
|
the
overall economic environment.
|
We are
indirectly exposed to natural gas and NGL commodity price risk. An
increase in natural gas prices or a decrease in NGL prices could result in a
decrease in the volume of NGLs fractionated by our Shoup and Armstrong
fractionators, which would result in a decrease in gross operating margin for
the South Texas NGL System.
A
decrease in demand for natural gas, NGL products or petrochemical products by
the petrochemical, refining or heating industries could materially adversely
affect our results of operations, cash flows and financial
position.
A decrease in demand for NGL products
by the petrochemical, refining or heating industries could materially adversely
affect our financial position, results of operations and cash
flows. Decreases in such demand may be caused by general economic
conditions, reduced demand by consumers for the end products made with NGL
products, increased competition from petroleum-based products due to pricing
differences, adverse weather conditions, government regulations affecting prices
and production levels of natural gas or the content of motor gasoline or other
reasons. For example:
|
§
|
Ethane. Ethane is
primarily used in the petrochemical industry as feedstock for ethylene,
one of the basic building blocks for a wide range of plastics and other
chemical products. If natural gas prices increase significantly
in relation to NGL product prices, or if the demand for ethylene falls
(and, therefore, the demand for ethane by NGL producers falls), it may be
more profitable for natural gas producers to leave the ethane in the
natural gas stream to be burned as fuel than to extract the ethane from
the mixed NGL stream for sale as an ethylene
feedstock.
|
|
§
|
Propane. The
demand for propane as a heating fuel is significantly affected by weather
conditions. Unusually warm winters could cause the demand for
propane to decline significantly and could cause a significant decline in
the volumes of propane that we
transport.
|
|
§
|
Isobutane. A
reduction in demand for motor gasoline additives may reduce demand for
isobutane.
|
|
§
|
Propylene. Propylene
is sold to petrochemical companies for a variety of uses, principally for
the production of polypropylene. Propylene is subject to rapid
and material price fluctuations. Any downturn in the domestic
or international economy could cause reduced demand for, and an oversupply
of propylene, which could cause a reduction in the volumes of propylene
that we transport.
|
Any
decrease in supplies of natural gas could adversely affect our business and
operating results. Our success depends on our ability to obtain access to new
sources of natural gas from both domestic production and LNG terminals, which
sources are dependent on factors beyond our control.
We cannot
give any assurance regarding the natural gas production industry’s ability to
find new domestic supply sources. Production from existing wells and
gas supply basins connected to our pipelines will naturally decline over time,
which means our cash flows associated with the gathering or transportation of
gas from these wells and basins will also decline over time. The
amount of natural gas reserves underlying these wells may also be less than we
anticipate, and the rate at which production from these reserves declines may be
greater than we anticipate. Accordingly, to maintain or increase
throughput levels on our pipelines, we must continually obtain access to new
supplies of natural gas. The primary factors affecting our ability to
obtain new sources of natural gas to our pipelines include:
|
§
|
the
level of successful drilling activity near our
pipelines;
|
|
§
|
our
ability to compete for these
supplies;
|
|
§
|
our
ability to connect our pipelines to the
suppliers;
|
|
§
|
the
successful completion of new liquefied natural gas (“LNG”) facilities near
our pipelines; and
|
|
§
|
our
gas quality requirements.
|
The level of drilling activity depends
on economic and business factors beyond our control. The primary factor that
impacts drilling decisions is the price of oil and natural gas. These
commodity prices reached record levels during 2008, but current prices have
declined in recent months. A sustained decline in natural gas prices
could result in a decrease in exploration and development activities in the
fields served by our pipelines, which would lead to reduced throughput levels on
our pipelines. Other factors that impact production decisions include
producers’ capital budget limitations, the ability of producers to obtain
necessary drilling and other governmental permits, the availability and cost of
drilling rigs and other drilling equipment and regulatory
changes. Because of these factors, even if new natural gas reserves
were discovered in areas served by our pipelines, producers may choose not to
develop those reserves or may connect them to different pipelines.
Imported LNG is expected to be a
significant component of future natural gas supply to the United
States. Much of this increase in LNG supplies is expected to be
imported through LNG facilities which have currently been developed or new LNG
facilities which have been announced to be developed over the next
decade. We cannot predict which, if any, of these announced, but as
yet unbuilt, projects will be constructed. In addition, unanticipated
increases in future natural gas supplies may not be made available to our
facilities and pipelines if (i) a significant number of these new projects fail
to be developed with their announced capacity, (ii) there are significant delays
in such development, (iii) they are built in locations where they are not
connected to our assets or (iv) they do not influence sources of supply on our
systems.
If we are not able to obtain new
supplies of natural gas to replace the natural decline in volumes from existing
supply basins, or if the expected increase in natural gas supply through
imported LNG is not realized, throughput on our pipelines would decline, which
could have a material adverse effect on our financial position, results of
operations and ability to make distributions to our unitholders.
Consistent
with industry practice, we do not obtain independent evaluations of natural gas
reserves dedicated to our pipeline systems, including our South Texas NGL
Pipeline & Storage System. Accordingly, volumes of natural gas gathered on
our pipeline systems in the future could be less than we anticipate, which could
adversely affect our cash flow and our ability to make cash distributions to
unitholders.
Consistent
with industry practice, we do not obtain independent evaluations of natural gas
reserves connected to our pipeline systems due to the unwillingness of producers
to provide reserve information as well as the cost of such
evaluations. Accordingly, we do not have estimates of total reserves
dedicated to our systems (or to processing and fractionation facilities such as
those serving EPO in south Texas) or the anticipated lives of such
reserves. If the total reserves or estimated lives of the reserves
connected to our pipeline systems, particularly in south Texas, are less than we
anticipate and we are unable to secure additional sources of natural gas or
NGLs, then the volumes of NGLs transported on our South Texas NGL Pipeline
System or natural gas gathered on our Acadian Gas System and other pipeline
systems in the future could be less than we anticipate. A decline in
the volumes of natural gas or NGLs gathered on our pipeline systems could have
an adverse effect on our business, results of operations, financial position and
our ability to make cash distributions to our unitholders.
We
face competition from third parties in our midstream energy
businesses.
Even if reserves exist in the areas
accessed by our facilities and are ultimately produced, we may not be chosen by
the producers in these areas to gather, transport, market, store or otherwise
handle the hydrocarbons that are produced. We compete with others,
including producers of oil and natural gas, for any such production on the basis
of many factors, including but not limited to geographic proximity to the
production, costs of connection, available capacity, rates and access to
markets.
Our transportation businesses compete
with other pipelines companies in the areas they serve. We also
compete with trucks, railroads and marine transportation companies in some of
the areas we serve. Competitive pressures may adversely affect our tariff
rates or volumes shipped.
In our natural gas gathering business,
we encounter competition in obtaining contracts to gather natural gas supplies,
and particularly new supplies. Competition in natural gas gathering
is based in large part on reputation, efficiency, system reliability, gathering
system capacity and price arrangements. Our key competitors in the
gas gathering segment include independent gas gatherers and major integrated
energy companies. Alternate gathering facilities are available to
producers we serve, and those producers may also elect to construct proprietary
gas gathering systems. If production delivered to our gathering
system declines, our revenues from such operations will decline.
Our
debt is provided under bank facilities that mature in 2011. The cost
to refinance these facilities may be materially higher. Our debt
level may limit our future financial and operating flexibility.
As of December 31, 2009, we had $175.0
million of indebtedness outstanding under our revolving credit agreement, which
matures in February 2011, with the ability to borrow up to an additional $121.7
million, subject to certain conditions and limitations, under the credit
agreement. We also had an additional $282.3 million of indebtedness
outstanding under our senior unsecured term loan, which matures in December
2011. The terms of these facilities were negotiated prior to the
financial crisis of 2008 and are more favorable than terms currently available
in the financial markets. Our level of indebtedness could have
important consequences to us, including:
|
§
|
our
ability to obtain additional financing, if necessary, for working capital,
capital expenditures, acquisitions or other purposes may be impaired or
such financing may not be available on favorable
terms;
|
|
§
|
covenants
contained in our existing and future credit and debt arrangements require
us to meet certain financial tests that may affect our flexibility in
planning for and reacting to changes in our business, including possible
acquisition opportunities;
|
|
§
|
we
may need a substantial portion of our cash flow to make principal and
interest payments on our indebtedness, reducing the funds that would
otherwise be available for operation, future business opportunities and
distributions to unitholders; and
|
|
§
|
our
debt level may make us more vulnerable than our competitors with less debt
to competitive pressures or a downturn in our business or the economy
generally.
|
Our ability to service our indebtedness
will depend upon, among other things, our future financial and operating
performance, which may be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which are beyond our
control. If our operating results are not sufficient to service our
current or future indebtedness, we may be forced to take actions such as
reducing distributions, reducing or delaying business activities, acquisition,
investments or capital expenditures, selling assets, restructuring or
refinancing our indebtedness, or seeking additional equity capital or bankruptcy
protection. We may not be able to affect any of these remedies on
satisfactory terms if at all.
Increases
in interest rates could materially adversely affect our business, results of
operations, cash flows and financial position.
We have
exposure to increases in interest rates. As of December 31, 2009, our
consolidated variable rate debt was effectively $282.3 million. The
remainder of our outstanding debt on this date reflects $175.0 million in
notional amount of floating-to-fixed interest rate swaps, which expire in
September 2010. As a result, significant increases in interest rates
could adversely affect our results of operations, cash flows and financial
position.
An
increase in interest rates may also cause a corresponding decline in demand for
equity investments, in general, and in particular for yield-based equity
investments such as our common units. Any such reduction in demand
for our common units resulting from other more attractive investment
opportunities may cause the trading price of our common units to
decline.
We
may not be able to fully execute our growth strategy if we encounter illiquid
capital markets or increased competition for investment
opportunities.
Our growth strategy contemplates the
development and acquisition of a wide range of midstream and other energy
infrastructure assets while maintaining a strong balance sheet. This
strategy includes constructing and acquiring additional assets and businesses to
enhance our ability to compete effectively and diversifying our asset portfolio,
thereby providing more stable cash flow. We regularly consider and
pursue potential joint ventures, stand alone projects or other transactions that
we believe may present opportunities to realize synergies, expand our role in
the energy infrastructure business and increase our market
position.
We will require substantial new capital
to finance the future development and acquisition of assets and
businesses. Any limitations on our access to capital may impair our
ability to execute this growth strategy. If our cost of debt or
equity capital becomes too expensive, our ability to develop or acquire
accretive assets will be limited. We also may not be able to raise
necessary funds on satisfactory terms, if at all.
The negative impact on the tightening
of the credit markets may have a material adverse effect on us resulting from,
but not limited to, an inability to expand facilities or finance the acquisition
of assets on favorable terms, if at all, increased financing costs or
financing with increasingly restrictive covenants. In addition, the
distribution yields of new equity issued may be higher than our historical
levels, making additional equity issuances more expensive.
We also compete for the types of assets
and businesses we would likely be interested in purchasing or
acquiring. Increased competition for a limited pool of assets could
result in our losing to other bidders more often or acquiring assets at less
attractive prices. Either occurrence would limit our ability to fully
execute our growth strategy. Our inability to execute our growth
strategy may materially adversely affect our ability to maintain or pay higher
distributions in the future.
Our
credit agreements contain operating and financial restrictions, including
covenants and restrictions that may be affected by events beyond our control, or
that may limit our business and/or financing activities.
The
operating and financial restrictions and covenants in our credit agreements and
any future financing agreements could restrict our ability to finance future
operations or capital needs or to expand or pursue our business
activities. For example, our credit agreements may restrict or limit
our ability to:
|
§
|
make
distributions if any default or event of default
occurs;
|
|
§
|
incur
additional indebtedness or guarantee other
indebtedness;
|
|
§
|
grant
liens or make certain negative
pledges;
|
|
§
|
make
certain loans or investments;
|
|
§
|
make
any material change to the nature of our business, including
consolidations, liquidations and dissolutions;
or
|
|
§
|
enter
into a merger, consolidation, sale and leaseback transaction or sale of
assets.
|
Our
ability to comply with the covenants and restrictions contained in our credit
agreements may be affected by events beyond our control, including prevailing
economic, financial and industry conditions. If market or other
economic conditions deteriorate, our ability to comply with these covenants may
be impaired. If we violate any of the restrictions, covenants, ratios
or tests in our credit agreement, a significant portion of our indebtedness may
become immediately due and payable, and our lenders’ commitment to make further
loans to us may terminate. We might not have, or be able to obtain,
sufficient funds to make these accelerated payments.
Restrictions
in our credit agreements could limit our ability to make distributions upon the
occurrence of certain events.
Our payment of principal and interest
on our debt will reduce cash available for distributions on our common
units. Furthermore, our credit agreements could limit our ability to
make distributions upon the occurrence of the following events, among
others:
|
§
|
failure
to pay any principal, interest, fees, expenses or other amounts when
due;
|
|
§
|
failure
of any representation or warranty made by us in our credit agreements to
be true and correct in any material
respect;
|
|
§
|
failure
to perform or otherwise comply with the covenants in the credit
agreements;
|
|
§
|
failure
to pay any other material debt;
|
|
§
|
a
bankruptcy or insolvency event involving us, our general partner or any of
our subsidiaries;
|
|
§
|
the
entry of, and failure to pay, one or more adverse judgments in excess of a
specified amount against which enforcement proceedings are brought or that
are not stayed pending appeal;
|
|
§
|
a
change in control of us;
|
|
§
|
a
judgment default or a default under any material agreement if such default
could have a material adverse effect on us;
and
|
|
§
|
the
occurrence of certain events with respect to employee benefit plans
subject to ERISA.
|
Any
subsequent refinancing of our current debt or any new debt could have similar or
more restrictive provisions. For more information regarding our
credit agreements, see Note 11 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report.
Our
pipeline integrity program may impose significant costs and liabilities on
us.
The DOT
issued final rules (effective March 2001 with respect to hazardous liquid
pipelines and February 2004 with respect to natural gas pipelines) requiring
pipeline operators to develop integrity management programs to comprehensively
evaluate their pipelines, and take measures to protect pipeline segments located
in what the rules refer to as “high consequence areas.” The final
rule resulted from the enactment of the Pipeline Safety Improvement Act of
2002. At this time, we cannot predict the ultimate costs of
compliance with this rule because those costs will depend on the number and
extent of any repairs found to be necessary as a result of the pipeline
integrity testing that is required by the rule. The majority of the
costs to comply with this integrity management rule are associated with pipeline
integrity testing and any repairs found to be necessary as a result of such
testing. Changes such as advances of in-line inspection tools,
identification of additional threats to a pipeline’s integrity and changes to
the amount of pipe determined to be located in “high consequence areas” can have
a significant impact on the costs to perform integrity testing and
repairs. We will continue our pipeline integrity testing programs to
assess and maintain the integrity of our pipelines. The results of
these tests could cause us to incur significant and unanticipated capital and
operating expenditures for repairs or upgrades deemed necessary to ensure the
continued safe and reliable operation of our pipelines.
In June
2008, the DOT issued a Final Rule extending its pipeline safety regulations,
including integrity management requirements, to certain rural onshore hazardous
liquid gathering lines and certain rural onshore low-stress hazardous liquid
pipelines within a buffer area around “unusually sensitive
areas.” The issuance of these new gathering and low-stress pipeline
safety regulations, including requirements for integrity management of those
pipelines, is likely to increase the operating costs of our pipelines subject to
such new requirements.
Our
growth strategy may adversely affect our results of operations if we do not
successfully integrate and manage the businesses that we acquire or if we
substantially increase our indebtedness and contingent liabilities to make
acquisitions.
Our growth strategy includes making
accretive acquisitions. As a result, from time to time, we will
evaluate and acquire assets and businesses that we believe complement our
existing operations. We may be unable to successfully integrate and
manage businesses we acquire in the future. We may incur substantial
expenses or encounter delays or other problems in connection with our growth
strategy that could negatively impact our results of operations, cash flows and
financial position. Moreover, acquisitions and business expansions
involve numerous risks, including but not limited to:
|
§
|
difficulties
in the assimilation of the operations, technologies, services and products
of the acquired companies or business
segments;
|
|
§
|
establishing
the internal controls and procedures that we are required to maintain
under the Sarbanes-Oxley Act of
2002;
|
|
§
|
managing
relationships with new joint venture partners with whom we have not
previously partnered;
|
|
§
|
experiencing
unforeseen operational interruptions or the loss of key employees,
customers, or suppliers;
|
|
§
|
inefficiencies
and complexities that can arise because of unfamiliarity with new assets
and the businesses associated with them, including with their markets;
and
|
|
§
|
diversion
of the attention of management and other personnel from day-to-day
business to the development or acquisition of new businesses and other
business opportunities.
|
If consummated, any acquisition or
investment would also likely result in the incurrence of indebtedness and
contingent liabilities and an increase in interest expense and depreciation,
accretion and amortization expenses. As a result, our capitalization
and results of operations may change significantly following an
acquisition. A substantial increase in our indebtedness and
contingent liabilities could have a material adverse effect on our results of
operations, cash flows and financial position. In addition, any
anticipated benefits of material acquisition, such as expected cost savings, may
not be fully realized, if at all.
Because
our general partner does not own incentive distribution rights in our
distributions, we may elect to acquire or build energy infrastructure assets
that have a lower expected return on investment than a similarly situated
publicly traded energy partnership whose partner owns incentive distribution
rights.
Duncan Energy Partners was formed in
part to support the growth objectives of EPO. EPO, the owner of our
general partner, elected to forgo incentive distribution rights with respect to
our distributions for the purpose of reducing our expected long-term cost of
equity capital. This should allow us to acquire or build energy
infrastructure assets with lower expected returns on investment that should
still be accretive, in terms of distributable cash flow, on a per unit
basis. Such expected returns on investment may not be considered
economically viable by other similarly situated publicly traded partnerships
whose general partner owns incentive distribution rights, including Enterprise
Products Partners. In addition, we may elect to participate in
capital projects with Enterprise Products Partners, whereby our expected return
on investment may be lower than that of Enterprise Products Partners, yet is
still ultimately expected to be accretive, in terms of distributable cash flow,
on a per unit basis for our common units. Should the returns and cash
flow from operations from such acquisitions or capital projects not materialize
as expected, we may not be able to support our cash distribution rate at current
levels or increase our cash distribution rate to partners in the
future.
We
may not be able to make acquisitions or to make acquisitions on economically
acceptable terms, which may limit our ability to grow.
We are limited in our ability to make
acquisitions by our business opportunity agreements with EPO and Enterprise GP
Holdings. These agreements entitle them to take business
opportunities for the benefit of themselves before allowing us to take
them. In addition, our ability to grow depends, in part, on our
ability to make acquisitions that result in an increase in the cash generated
from operations per unit. If we are unable to make these accretive
acquisitions either because we are (1) unable to identify attractive acquisition
candidates or negotiate acceptable purchase contracts with them, (2) unable to
obtain financing for these acquisitions on economically acceptable terms, or (3)
outbid by competitors, then our future growth and ability to maintain and
increase over time distributions will be limited.
Acquisitions
that appear to increase our cash from operations may nevertheless reduce our
cash from operations on a per unit basis.
Even if we make acquisitions that we
believe will increase our cash from operations, these acquisitions may
nevertheless reduce our cash from operations on a per unit basis. Any
acquisition involves assumptions that may not materialize and potential risks
that may occur. These risks include our inability to achieve our
operating and financial projections or to integrate an acquired business
successfully, the assumption of unknown liabilities for which we become liable
and the loss of key employees or key customers.
If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly, and our unitholders will not have the opportunity to
evaluate the economic, financial and other relevant information that we will
consider in determining the application of these funds and other
resources.
We
depend in large part on EPO and the continued success of its business as we
operate our assets as part of their value chain, and adverse changes in its
related businesses may reduce our revenue, earnings or cash available for
distribution.
We have
entered into a number of material contracts with EPO and its subsidiaries
relating to midstream energy services and arrangements. Our cash
flows and financial position depend in large part on the continued success of
EPO as we operate our assets as part of its value chain. Any adverse
changes in the business of EPO, due to market conditions, sales of assets or
otherwise, or the failure of EPO to renew any of its material agreements with
us, could reduce our revenue, earnings or cash available for
distribution. See Note 15 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for additional
information regarding our relationship with EPO.
The
interruption of distributions to us from our subsidiaries may affect our ability
to satisfy our obligations and to make distributions to our
partners.
We are a holding company with no
business operations, and our operating subsidiaries conduct all of our
operations and own all of our operating assets. Our only significant
assets are the ownership interests we own in our subsidiaries. As a
result, we depend upon the earnings and cash flow of our subsidiaries and
Evangeline and the distribution of that cash to us in order to meet our
obligations and to allow us to make distributions to our
partners. The ability of our subsidiaries and Evangeline to make
distributions to us may be restricted by, among other things, the provisions of
existing and future indebtedness, applicable state partnership and limited
liability company laws and other laws and regulations, including FERC
policies.
We also own a membership interest in
Enterprise Texas, which interest has a stated fixed return. Although
we have effective priority rights to specified quarterly distribution amounts
ahead of any distributions on EPO’s minority equity interests in Enterprise
Texas, the inability of Enterprise Texas Pipeline to make distributions of the
fixed returns in full each quarter would have a material adverse impact on our
ability to make distributions to our partners and could affect our ability to
satisfy other debt obligations.
The
credit and risk profile of our general partner and its owners could adversely
affect our risk profile, which could increase our borrowing costs, hinder our
ability to raise capital or impact potential future credit ratings.
The credit and business risk profiles
of a general partner or owners of a general partner may be factors in credit
evaluations of a limited partnership by the nationally recognized debt rating
agencies. This is because the general partner controls the business
activities of the partnership, including its cash distribution policy and
acquisition strategy and business risk profile. Another factor that
may be considered is the financial position of our general partner and its
owners, including the degree of their financial leverage and their dependence on
cash flow from the partnership to service their indebtedness.
If we were to seek a credit rating in
the future, our credit rating may be adversely affected by the leverage of the
owners of our general partner, as credit rating agencies may consider these
entities’ leverage because of their ownership interest in and control of us, the
strong operational links between them and their affiliates and us, and our
reliance on EPO for a substantial percentage of our revenue. Any such
adverse effect on our credit rating would increase our cost of borrowing or
hinder our ability to raise money in the capital markets, which would impair our
ability to grow our business and make distributions to unitholders.
Affiliates of EPCO and Enterprise
Products Partners, the indirect owner of our general partner, have significant
indebtedness outstanding and are dependent principally on the cash distributions
from their limited partner interests in Enterprise Products Partners and
Enterprise GP Holdings to service such indebtedness. Any
distributions by Enterprise Products Partners and Enterprise GP Holdings to such
entities will be made only after satisfying their then-current obligations to
their creditors. Although we have taken certain steps in our
organizational structure, financial reporting and contractual relationships to
reflect the separateness of us and our general partner from the entities that
control our general partner, and other entities controlled by EPCO, our credit
ratings and business risk profile could be adversely affected if the ratings and
risk profiles of EPCO or the entities that control our general partner were
viewed as substantially lower or more risky than ours.
A
natural disaster, catastrophe or other event could result in severe personal
injury, property damage and environmental damage, which could curtail our
operations and otherwise materially adversely affect our cash flow and,
accordingly, affect the market price of our common units.
Some of
our operations involve risks of personal injury, property damage and
environmental damage, which could curtail our operations and otherwise
materially adversely affect our cash flow. For example, natural gas
facilities operate at high pressures, sometimes in excess of 1,100 pounds per
square inch. Pipelines may suffer inadvertent damage from
construction, farm and utility equipment. Virtually all of our
operations are exposed to potential natural disasters, including hurricanes,
tornadoes, storms and floods. The location of our assets and our
customers’ assets in the Gulf Coast region makes them particularly vulnerable to
hurricane risk.
If one or
more facilities that we own or that deliver natural gas or other products to us
are damaged by severe weather or any other disaster, accident, catastrophe or
event, our operations could be significantly interrupted. Similar
interruptions could result from damage to production or other facilities that
supply our facilities or other stoppages arising from factors beyond our
control. These interruptions might involve significant damage to
people, property or the environment, and repairs might take from a week or less
for a minor incident to six months or more for a major
interruption. Any event that interrupts the revenues generated by our
operations, or which causes us to make significant expenditures not covered by
insurance, could reduce our cash available for paying distributions and,
accordingly, adversely affect the market price of our common units.
We
believe that EPCO maintains adequate insurance coverage on behalf of us,
although insurance will not cover many types of interruptions that might occur
and will not cover amounts up to applicable deductibles. As a result
of market conditions, premiums and deductibles for certain insurance policies
can increase substantially, and in some instances, certain insurance may become
unavailable or available only for reduced amounts of coverage. For
example, changes in the insurance markets subsequent to the hurricanes in 2005
and 2008 have made it more difficult for us to obtain certain types of
coverage. As a result, EPCO may not be able to renew existing
insurance policies on behalf of us or procure other desirable insurance on
commercially reasonable terms, if at all. If we were to incur a
significant liability for which we were not fully insured, it could have a
material adverse effect on our financial position and results of
operations. In addition, the proceeds of any such insurance may not
be paid in a timely manner and may be insufficient if such an event were to
occur. See Note 18 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report for more information regarding
insurance matters.
Our
construction of new assets is subject to regulatory, environmental, political,
legal and economic risks, which may result in delays, increased costs or
decreased cash flows.
One of the ways we intend to grow our
business is through the construction of new midstream energy
assets. We cannot ensure that our construction projects will not be
delayed due to government permits, weather conditions or other factors beyond
our control. The construction of new assets also involves numerous
operational, regulatory, environmental, political and legal risks beyond our
control and may require the expenditure of significant amounts of
capital. These potential risks include, among other things, the
following:
|
§
|
we
may be unable to complete construction projects on schedule or at the
budgeted cost due to the unavailability of required construction personnel
or materials, accidents, weather conditions or an inability to obtain
necessary permits;
|
|
§
|
we
will not receive any material increases in revenues until the project is
completed, even though we may have expended considerable funds during the
construction phase, which may be
prolonged;
|
|
§
|
we
may construct facilities to capture anticipated future growth in
production or demand in a region in which such growth does not
materialize;
|
|
§
|
since
we are not engaged in the exploration for and development of natural gas
reserves, we may not have access to third-party estimates of reserves in
an area prior to our constructing facilities in the area. As a
result, we may construct facilities in an area where the reserves are
materially lower than we
anticipate;
|
|
§
|
where
we do rely on third-party estimates of reserves in making a decision to
construct facilities, these estimates may prove to be inaccurate because
there are numerous uncertainties inherent in estimating reserves;
and
|
|
§
|
we
may be unable to obtain rights-of-way to construct additional pipelines or
the cost to do so may be
uneconomical.
|
A
materialization of any of these risks could adversely affect our ability to
achieve growth in the level of our cash flows or realize benefits from expansion
opportunities or construction projects.
Federal,
state or local regulatory measures could materially affect our business, results
of operations, cash flows and financial position.
The intrastate natural gas pipeline
transportation services we provide are subject to various Texas and Louisiana
state laws and regulations that apply to the rates we charge and the terms and
conditions of the services we offer. Although state regulation
typically is less onerous than FERC regulation, proposed and existing rates
subject to state regulation and the provision of our services on a
non-discriminatory basis are subject to challenge by protest and
complaint, respectively. In addition, the transportation and storage
services furnished by our intrastate natural gas facilities on behalf of
interstate natural gas pipelines or certain local distribution companies are
regulated by the FERC pursuant to Section 311 of the NGA. Pursuant to
the NGA, we are required to offer those services on an open and
nondiscriminatory basis at a fair and equitable rate. Such
FERC-regulated NGA Section 311 rates also may be subject to challenge and
successful challenges may adversely affect our revenues.
Although our natural gas gathering
systems are generally exempt from FERC regulation under the NGA, FERC regulation
still significantly affects our natural gas gathering business. In
recent years, the FERC has pursued pro-competition policies in its regulation of
interstate natural gas pipelines. If the FERC does not continue this
approach, it could have an adverse effect on the rates we are able to charge in
the future. In addition, the distinction between FERC-regulated
transmission service and federally unregulated gathering services is the subject
of regular litigation, so, in such a circumstance, the classification
and
regulation
of some of our gathering facilities may be subject to change based on future
determinations by the FERC and the courts. Additional rules and
legislation pertaining to these matters are considered and adopted from time to
time at both federal and state levels. We cannot predict what effect,
if any, such regulatory changes and legislation might have on our operations,
but we could be required to incur additional capital expenditures.
The tariff rates and terms of service
of the intrastate liquids pipeline transportation services we provide are
subject to various state laws and regulations. Although state
regulation typically is less onerous than FERC regulation, our intrastate rates
and terms of service are subject to challenge by complaint.
The STB regulates transportation on
interstate propylene pipelines. The current version of the ICA and
its implementing regulations give the STB authority to regulate the rates we
charge for service on the propylene pipelines and generally requires that our
rates and practices be just and reasonable and nondiscriminatory. The
rates we charge for movements on our propylene pipelines may be subject to
challenge and any successful challenge to those rates could adversely affect our
revenues. Our interstate propylene pipelines formerly were regulated
by the FERC, and we cannot guarantee that the FERC will not reassert
jurisdiction over those facilities in the future.
For a
general overview of federal, state and local regulation applicable to our
assets, see Item 1 and 2 of this annual report.
Environmental
costs and liabilities and changing environmental regulation, including climate
change regulation, could materially affect our results of operations, cash flows
and financial position.
Our
operations are subject to extensive federal, state and local regulatory
requirements relating to environmental affairs, health and safety, waste
management and chemical and petroleum products. Further, we cannot
ensure that existing environmental regulations will not be revised or that new
regulations, such as regulations designed to reduce the emissions of greenhouse
gases, will not be adopted or become applicable to us. Governmental
authorities have the power to enforce compliance with applicable regulations and
permits and to subject violators to civil and criminal penalties, including
substantial fines, injunctions or both. Certain environmental laws,
including CERCLA and analogous state laws and regulations, impose strict, joint
and several liability for costs required to cleanup and restore sites where
hazardous substances or hydrocarbons have been disposed or otherwise
released. Moreover, third parties, including neighboring landowners,
may also have the right to pursue legal actions to enforce compliance or to
recover for personal injury and property damage allegedly caused by the release
of hazardous substances, hydrocarbons or other waste products into the
environment.
We will
make expenditures in connection with environmental matters as part of normal
capital expenditure programs. However, future environmental law
developments, such as stricter laws, regulations, permits or enforcement
policies, could significantly increase some costs of our operations, including
the handling, manufacture, use, emission or disposal of substances and
wastes.
Climate change regulation is one area
of potential future environmental law development. Studies have
suggested that emissions of certain gases, commonly referred to as “greenhouse
gases,” may be contributing to warming of the Earth’s
atmosphere. Methane, a primary component of natural gas, and carbon
dioxide, a byproduct of the burning of natural gas, are examples of greenhouse
gases. The U.S. Congress is considering legislation to reduce
emissions of greenhouse gases. In addition, at least nine states in
the Northeast and five states in the West have developed initiatives to regulate
emissions of greenhouse gases, primarily through the planned development of
greenhouse gas emission inventories and/or regional greenhouse gas cap and trade
programs.
On December 7, 2009, the EPA
announced its findings that emissions of greenhouse gases present an
endangerment to human health and the environment. These findings by the EPA
allow the agency to proceed with the adoption and implementation of regulations
that would restrict emissions of greenhouse gases under existing provisions of
the CAA. In late September 2009, the EPA had proposed two sets
of
CAA
regulations in anticipation of finalizing its endangerment findings that would
require a reduction in emissions of greenhouse gases from motor vehicles and,
also, could trigger permit review for greenhouse gas emissions from certain
stationary sources. In addition, on September 22, 2009, the EPA
issued a final CAA rule requiring the reporting of greenhouse gas emissions from
specified large greenhouse gas emission sources in the United States beginning
in 2011 for emissions occurring in 2010. These regulations will
require reporting for some of our facilities, and additional EPA regulations
expected to be adopted in 2010 will require other of our facilities to report
their greenhouse gas emissions, possibly beginning in 2012 for emissions
occurring in 2011.
Also, on June 26, 2009, the U.S. House
of Representatives passed ACESA, which would establish an economy-wide
cap-and-trade program intended to reduce U.S. emissions of “greenhouse
gases.” ACESA would require a 17 percent reduction in greenhouse gas
emissions from 2005 levels by 2020 and just over an 80 percent reduction of such
emissions by 2050. Under this legislation, the EPA would issue a
capped and steadily declining number of tradable emissions allowances to certain
major sources of greenhouse gas emissions so that such sources could continue to
emit greenhouse gases into the atmosphere. The cost of these
allowances would be expected to escalate significantly over time. The
net effect of ACESA would be to impose increasing costs on the combustion of
carbon-based fuels such as oil, refined petroleum products, and natural
gas. The U.S. Senate has begun work on its own legislation for
restricting domestic greenhouse gas emissions and the Obama Administration has
indicated its 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, the adoption and implementation of any CAA regulations, and any future
federal, state or local 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 other
hydrocarbon products that we transport, store or otherwise handle in connection
with our midstream services. The effect on our operations could include
increased costs to operate and maintain our facilities, install new emission
controls on our facilities, measure and report our emissions, acquire allowances
to authorize our greenhouse gas emissions, pay any taxes related to our
greenhouse gas emissions and administer and manage a greenhouse gas emissions
program. While we may be able to include some or all of such
increased costs in the rates charged by our pipelines or other facilities, such
recovery of costs is uncertain and may depend on events beyond our control,
including the outcome of future rate proceedings before the FERC and the
provisions of any final legislation.
Global
warming, if occurring, may also impact our operations directly, including
increased maintenance costs for our facilities, increased flooding and severe
weather risks for our facilities that are located in low-lying areas and coastal
regions, and reduced demand for hydrocarbon products that may reduce demand and
volumes of the products that we fractionate, transport, market and
store.
We
are subject to strict regulations at many of our facilities regarding employee
safety, and failure to comply with these regulations could adversely affect our
ability to make distributions to our unitholders.
The
workplaces associated with our pipelines are subject to the requirements of the
OSHA and comparable state statutes that regulate the protection of the health
and safety of workers. In addition, the OSHA hazard communication
standard requires that we maintain information about hazardous materials used or
produced in our operations and that we provide this information to employees,
state and local governmental authorities and local residents. The
failure to comply with OSHA requirements or general industry standards, keep
adequate records or monitor occupational exposure to regulated substances could
have a material adverse effect on our business, financial position, results of
operations and ability to make distributions to our unitholders.
We
depend on EPO and certain other key customers for a significant portion of our
revenues. The loss of any of these key customers could result in a decline in
our revenues and cash available to make distributions to our
unitholders.
We rely on a limited number of
customers for a significant portion of revenues. For the year ended
December 31, 2009, 2008 and 2007, EPO and its affiliates accounted for
approximately 33.8%, 23.6% and 16.1% of our total consolidated revenues,
respectively. In addition, several of our assets also rely on only
one or two customers for the asset’s cash flow. For example, the only
shipper on a segment of our South Texas NGL Pipeline System is EPO; there are
only two customers on our Lou-Tex Propylene Pipeline; there is only one customer
on our Sabine Propylene Pipeline; and there is only one shipper on the pipeline
held by Evangeline. In order for new customers to use these
pipelines, we or the new shippers would be required to construct interim
pipeline connections.
We may be unable to negotiate
extensions or replacements of these contracts and those with other key customers
on favorable terms. The loss of all or even a portion of the
contracted volumes of these customers, as a result of competition,
creditworthiness or otherwise, could have a material adverse effect on our
financial position, results of operations and ability to make distributions to
our unitholders, unless we are able to contract for comparable volumes from
other customers at favorable rates.
We
are exposed to the credit risks of our key customers, and any material
nonpayment or nonperformance by our key customers could reduce our ability to
make distributions to our unitholders.
We are subject to risks of loss
resulting from nonpayment or nonperformance by our customers. Any material
nonpayment or nonperformance by our key customers could reduce our ability to
make distributions to our unitholders. Furthermore, some of our
customers may be highly leveraged and subject to their own operating and
regulatory risks. We generally do not require collateral for our
accounts receivable. If we fail to adequately assess the
creditworthiness of existing or future customers, unanticipated deterioration in
their creditworthiness and any resulting increase in nonpayment or
nonperformance by them could have a material adverse effect on our business,
results of operations, financial position and ability to make cash distributions
to our unitholders.
We
depend on the leadership and involvement of key personnel for the success of our
businesses.
We depend on the leadership,
involvement and services of key personnel. The loss of leadership and
involvement or the services of key members of our senior management team,
including Dan L. Duncan, could have a material adverse effect on our business,
financial position, results of operations, cash flows and market price of our
securities.
Successful
development of LNG import terminals outside our areas of operations could reduce
the demand for our services.
Development of new, or expansion of
existing, LNG facilities outside our areas of operations could reduce the need
for customers to transport natural gas from supply basins connected to our
pipelines. This could reduce the amount of gas transported by our
pipelines for delivery off-system to other intrastate or interstate pipelines
serving these customers. If we are not able to replace these volumes
with volumes to other markets or other regions, throughput on our pipelines
would decline which could have a material adverse effect on our financial
position, results of operations and ability to make distributions to our
unitholders.
We
do not own all of the land on which our pipelines and facilities are located,
which could disrupt our operations.
We do not own all of the land on which
our pipelines and facilities are located, and we are therefore subject to the
risk of increased costs to maintain necessary land use. We obtain the
rights to construct and operate certain of our pipelines and related facilities
on land owned by third parties and
governmental
agencies for a specific period of time. Our loss of these rights,
through our inability to renew right-of-way contracts or otherwise, or increased
costs to renew such rights, could have a material adverse effect on our
business, results of operations, financial position and ability to make
distributions to our unitholders.
Mergers
among our customers or competitors could result in lower volumes being shipped
on our pipelines, thereby reducing the amount of cash we generate.
Mergers among our existing customers or
competitors could provide strong economic incentives for the combined entities
to utilize systems other than ours and we could experience difficulty in
replacing lost volumes and revenues. Because most of our operating
costs are fixed, a reduction in volumes would result in not only a reduction of
revenues, but also a decline in net income and cash flow of a similar magnitude,
which would reduce our ability to meet our financial obligations and make
distributions to our unitholders.
Risks
Inherent in an Investment in Us
Enterprise
Products Partners and its affiliates, EPO and EPCO and its affiliates may
compete with us, and business opportunities may be directed by contract to those
affiliates prior to us under the administrative services agreement.
Our
partnership agreement does not prohibit Enterprise Products Partners and its
affiliates, EPO and EPCO and their affiliates, other than our general partner,
from owning and operating natural gas and NGL pipelines and storage assets or
engaging in businesses that otherwise compete directly or indirectly with
us. In addition, Enterprise Products Partners, EPO and EPCO may
acquire, construct or dispose of additional midstream energy or other natural
gas assets in the future, without any obligation to offer us the opportunity to
purchase or construct any of these assets.
Under the
ASA, if any business opportunity, other than a business opportunity to acquire
general partner interests and other related equity securities in a publicly
traded partnership, is presented to EPCO and its affiliates, us and our general
partner, EPO, Enterprise Products Partners and its general partner, or
Enterprise GP Holdings and its general partner, then EPO will have the first
right to pursue such opportunity for itself or, in its sole discretion, to
affirmatively direct the opportunity to us. If EPO abandons the
business opportunity for itself or for us, then Enterprise GP Holdings will have
the second right to pursue such opportunity. If any business
opportunity to acquire general partner interests and other related equity
securities in a publicly traded partnership is presented, then Enterprise GP
Holdings will have the right to pursue such opportunity before EPO is given the
opportunity to pursue it for itself or to direct it to
us. Accordingly, we are limited by contract in our ability to take
certain business opportunities for our partnership. See Note 15 of
the Notes to Consolidated Financial Statements included under Item 8 of this
annual report for more information regarding the ASA.
Our
general partner and its affiliates own a controlling interest in us and have
conflicts of interest and limited fiduciary duties, which may permit them to
favor their own interests to our detriment.
As of December 31, 2009, EPO indirectly
owned a 0.7% general partner interest and beneficially owned approximately 58.6%
of our outstanding common units and controls our general partner, which controls
us. Although our general partner has a fiduciary duty to manage us in
a manner beneficial to us and our unitholders, the directors and officers of our
general partner have a fiduciary duty to manage it and our general partner in a
manner beneficial to Enterprise Products Partners and its
affiliates. Furthermore, certain directors and officers of our
general partner may be directors or officers of affiliates of our general
partner. Conflicts of interest may arise between Enterprise Products
Partners and its affiliates, including our general partner, on the one hand, and
us and our unitholders, on the other hand. As a result of these
conflicts, our general partner may favor its own interests and the interests of
its affiliates over the interests of our unitholders. These potential
conflicts include, among others, the following situations:
|
§
|
Enterprise
Products Partners, EPCO and their affiliates may engage in substantial
competition with us on the terms set forth in the
ASA.
|
|
§
|
Neither
our partnership agreement nor any other agreement requires EPCO,
Enterprise Products Partners, and Enterprise GP Holdings or their
affiliates (other than our general partner) to pursue a business strategy
that favors us. Directors and officers of EPCO and the general
partners of Enterprise Products Partners and Enterprise GP
Holdings and their affiliates have a fiduciary duty to make
decisions in the best interest of their shareholders or unitholders, which
may be contrary to our interests.
|
|
§
|
Our
general partner is allowed to take into account the interests of parties
other than us, such as EPCO, Enterprise Products Partners and Enterprise
GP Holdings and their affiliates, in resolving conflicts of interest,
which has the effect of limiting its fiduciary duty to our
unitholders.
|
|
§
|
Some
of the employees of EPCO who provide services to us also may devote
significant time to the business of Enterprise Products Partners and
Enterprise GP Holdings, and will be compensated by EPCO for such
services.
|
|
§
|
Our
partnership agreement limits the liability and reduces the fiduciary
duties of our general partner, while also restricting the remedies
available to our unitholders for actions that, without these limitations,
might constitute breaches of fiduciary duty. By purchasing
common units, unitholders will be deemed to have consented to some actions
and conflicts of interest that might otherwise constitute a breach of
fiduciary or other duties under applicable
law.
|
|
§
|
Our
general partner determines the amount and timing of asset purchases and
sales, operating expenditures, capital expenditures, borrowings,
repayments of indebtedness, issuances of additional partnership securities
and cash reserves, each of which can affect the amount of cash that is
available for distribution to our
unitholders.
|
|
§
|
Our
general partner determines which costs, including allocated overhead,
incurred by it and its affiliates are reimbursable by
us.
|
|
§
|
EPO may
propose to contribute additional assets to us and, in making such
proposal, the directors of EPO have a fiduciary duty to EPO’s members and
not to our unitholders.
|
|
§
|
Our
partnership agreement does not restrict our general partner 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.
|
|
§
|
Our
general partner intends to limit its liability regarding our contractual
obligations.
|
|
§
|
Our
general partner may exercise its rights to call and purchase all of our
common units if, at any time, it and its affiliates own 80% or more of the
outstanding common units.
|
|
§
|
Our
general partner controls the enforcement of obligations owed to us by it
and its affiliates, including the
ASA.
|
|
§
|
Our
general partner decides whether to retain separate counsel, accountants or
others to perform services for us.
|
See Note
15 of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report for additional information regarding our relationships with
EPCO and EPO.
We
may be limited in our ability to consummate transactions, including acquisitions
with affiliates of our general partner.
We will have inherent conflicts of
interest with affiliates of our general partner, including Enterprise Products
Partners. These conflicts may cause the ACG Committees of these
entities not to approve, or unitholders of these entities to dispute, any
transactions that may be proposed or consummated between or among us and these
affiliates. This may inhibit or prevent us from consummating
transactions, including acquisitions, with them.
EPCO’s
employees may be subjected to conflicts in managing our business and the
allocation of time and compensation costs between our business and the business
of EPCO and its other affiliates.
We have no officers or employees and
rely solely on officers of our general partner and employees of
EPCO. Certain of our officers are also officers of EPCO and other
affiliates of EPCO. These relationships may create conflicts of
interest regarding corporate opportunities and other matters, and the resolution
of any such conflicts may not always be in our or our unitholders’ best
interests. In addition, these overlapping officers allocate their
time among us, EPCO and other affiliates of EPCO. These officers face
potential conflicts regarding the allocation of their time, which may adversely
affect our business, results of operations and financial position.
We have entered into the ASA, which
governs business opportunities among entities controlled by EPCO, which includes
us and our general partner, Enterprise GP Holdings and its general partner and
Enterprise Products Partners and its general partner. For information
regarding how business opportunities are handled under the ASA within the EPCO
group of companies, see Item 13 of this annual report.
We do not have a separate compensation
committee, and aspects of the compensation of our executive officers and other
key employees, including base salary, are not reviewed or approved by our
independent directors. The determination of executive officer and key
employee compensation could involve conflicts of interest resulting in
economically unfavorable arrangements for us. For a discussion of our
executive compensation policies and procedures, see Item 11 of this annual
report.
The
global financial crisis and its ongoing effects may have impacts on our business
and financial position that we currently cannot predict.
We may face significant challenges if
conditions in the financial markets revert to those that existed in the fourth
quarter of 2008 and during 2009. Our ability to access the capital
markets may be severely restricted at a time when we would like, or need, to do
so, which could have an adverse impact on our ability to meet capital
commitments and achieve the flexibility needed to react to changing economic and
business conditions. The credit crisis could have a negative impact
on our lenders or customers, causing them to fail to meet their obligations to
us. Additionally, demand for our services and products depends on
activity and expenditure levels in the energy industry, which are directly and
negatively impacted by depressed oil and gas prices. Also, a decrease
in demand for NGLs by the petrochemical and refining industries due to a
decrease in demand for their products as a result of general economic conditions
would likely impact demand for our services and products. Any of
these factors could lead to reduced usage of our pipelines and energy logistics
services, which could have a material negative impact on our revenues and
prospects.
An
affiliate of EPO has the power to appoint and remove our directors and
management.
Because
EPO beneficially owns 100% of DEP GP, it has the ability to elect all the
members of the board of directors of our general partner. Our general
partner has control over all decisions related to our
operations. Furthermore, the goals and objectives of EPO relating to
us may not be consistent with those of a majority of the public
unitholders.
Our
general partner has a limited call right that may require unitholders to sell
their common units at an undesirable time or price.
If at any time after December 8, 2010,
our general partner and its affiliates own 80% or more of our outstanding common
units, our general partner will have the right, which it may assign to any of
its affiliates or to us, but not the obligation, to acquire all, but not less
than all, of the common units held by unaffiliated persons at a price equal to
the greater of:
|
§
|
the
average of the daily closing prices of the common units over the 20
trading days preceding the date three days before notice of exercise of
the call right is first mailed; and
|
|
§
|
the
highest price paid by our general partner or any of its affiliates for
common units during the 90-day period preceding the date such notice is
first mailed.
|
As a result, our unitholders may be
required to sell their common units at a price that is less than the initial
offering price or, because of the manner in which the purchase price is
determined, at a price less than the then current market price of our common
units. In addition, this call right may be exercised at an otherwise
undesirable time or price and unitholders may not receive any return on their
investment. Our unitholders may also incur a tax liability upon a
sale of their common units. Our general partner is not obligated to
obtain a fairness opinion regarding the value of the common units to be
repurchased by it upon exercise of the call right. There is no
restriction in our partnership agreement that prevents our general partner from
issuing additional common units or other equity securities and exercising its
call right. If our general partner exercised its call right, the
effect would be to take us private and, if our common units were subsequently
deregistered, we might no longer be subject to the reporting requirements of the
Securities Exchange Act of 1934, as amended, or the “Exchange
Act”. As of February 1, 2010, affiliates of Enterprise Products
Partners own our general partner and approximately 58.6% of our outstanding
common units.
Our
partnership agreement limits our general partner’s fiduciary duties to
unitholders and restricts the remedies available to unitholders for actions
taken by our general partner that might otherwise constitute breaches of
fiduciary duty.
Our
partnership agreement contains provisions that reduce the standards to which our
general partner would otherwise be held by state fiduciary duty
law. For example, our partnership agreement:
|
§
|
permits
our general partner to make a number of decisions in its individual
capacity, as opposed to in its capacity as our general
partner. This entitles our general partner to consider only the
interests and factors that it desires, and it has no duty or obligation to
give any consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include the
exercise of its limited call right, its rights to vote or transfer our
common units it owns, its registration rights and the determination of
whether to consent to any merger or consolidation of the partnership, or
amendment to the partnership
agreement;
|
|
§
|
provides
in the absence of bad faith by the ACG Committee or our general partner,
the resolution, action or terms made, taken or provided in connection with
a potential conflict of interest transaction will be conclusive and
binding on all persons (including all partners) and will not constitute a
breach of the partnership agreement or any standard of care or duty
imposed by law;
|
|
§
|
provides
the general partner shall not be liable to the partnership or any partner
for its good faith reliance on the provisions of the partnership agreement
to the extent it has duties, including fiduciary duties, and liabilities
at law or in equity;
|
|
§
|
generally
provides that affiliate transactions and resolutions of conflicts of
interest not approved by the ACG Committee of the board of directors of
our general partner must be on terms no less favorable to us than those
generally provided to or available from unrelated third parties or be
“fair and reasonable” to us;
|
|
§
|
provides
that it shall be presumed that the resolution of any conflicts of interest
by our general partner or the audit, conflicts and governance committee
was not made in bad faith, and in any proceeding brought by or on behalf
of any limited partner or us, the person bringing or prosecuting such
proceeding will have the burden of overcoming such presumption;
and
|
|
§
|
provides
that our general partner and its officers and directors will not be liable
for monetary damages to us or our limited partners for any acts or
omissions unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that the general
partner or those other persons acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted with
knowledge that the conduct was
criminal.
|
By purchasing a common unit, a
unitholder will become bound by the provisions of our partnership agreement,
including the provisions described above.
Unitholders
have limited voting rights and are not entitled to elect our general partner or
its directors, which could lower the trading price of our common
units.
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 will have no right to elect our
general partner or its board of directors on an annual or other continuing
basis. The board of directors of our general partner, including the
independent directors, is chosen entirely by its owners and not by the
unitholders. Furthermore, even if our unitholders were dissatisfied
with the performance of our general partner, they will, practically speaking,
have a limited ability to remove our general partner. As a result of
these limitations, the price at which our common units trade could be diminished
because of the absence or reduction of a control premium in the trading
price.
The vote
of the holders of at least 66 2/3% of all outstanding common units is required
to remove our general partner. As of February 1, 2010, affiliates of
Enterprise Products Partners, which owns our general partner, owned
approximately 58.6% of our outstanding common units.
We
may issue additional units without our unitholders’ approval, which would dilute
our unitholders’ ownership interests.
At any time, we may issue an unlimited
number of limited partner interests of any type without the approval of our
unitholders. Our partnership agreement does not give unitholders the
right to approve our issuance of equity securities ranking junior to our common
units at any time. In addition, our partnership agreement does not
prohibit the issuance by our subsidiaries of equity securities, which may
effectively rank senior to our common units. The issuance by us of
additional common units or other equity securities will have the following
effects:
|
§
|
the
ownership interest of unitholders immediately prior to the issuance will
decrease;
|
|
§
|
the
amount of cash available for distributions on each common unit may
decrease;
|
|
§
|
the
relative voting strength of each previously outstanding common unit may be
diminished;
|
|
§
|
the
ratio of taxable income to distributions may increase;
and
|
|
§
|
the
market price of our common units may
decline.
|
Our
partnership agreement restricts the voting rights of unitholders owning 20% or
more of our common units.
Our
partnership agreement restricts unitholders’ voting rights by providing that any
common units held by a person that owns 20% or more of any class of units then
outstanding, other than our general
partner, its
affiliates, their transferees and persons who acquired such units with the prior
approval of the board of directors of our general partner, cannot vote on any
matter. Our partnership agreement also contains provisions limiting
the ability of common unitholders to call meetings or to acquire information
about our operations, as well as other provisions limiting common unitholders’
ability to influence the manner or direction of management.
We
have a holding company structure in which our subsidiaries conduct our
operations and own our operating assets, which may affect our ability to make
distributions to our unitholders.
We are a partnership holding company
and our operating subsidiaries conduct all of our operations and own all of our
operating assets. We have no significant assets, other than the
ownership interests, in our subsidiaries and Evangeline. As a result,
our ability to make distributions to our unitholders depends on the performance
of our subsidiaries and Evangeline and their ability to distribute funds to
us. The ability of our subsidiaries and Evangeline to make
distributions to us may be restricted by, among other things, the provisions of
existing and future indebtedness, applicable state partnership and limited
liability company laws and other laws and regulations, including FERC
policies. For example, all cash flows from Evangeline are currently
used to service its debt.
Affiliates of Enterprise Products
Partners currently own a 34% minority equity interest in certain of our
operating subsidiaries and a 49% equity interest in our remaining operating
subsidiaries. These affiliates have a right of first refusal to
acquire these subsidiaries or their material assets if we desire to sell them,
other than inventory and other assets sold in the ordinary course of
business. These rights may adversely affect our ability to dispose of
these assets. In addition, Duncan Energy Partners’ ownership interest
in Mont Belvieu Caverns may be diluted, and the cash flow from our NGL Pipelines
& Services segment may be reduced, if Duncan Energy Partners does not
contribute a proportionate share of certain future costs to fund expansion
projects at Mont Belvieu Caverns.
We
do not have the same flexibility as other types of organizations to accumulate
cash and equity to protect against illiquidity in the future.
Unlike a
corporation, our partnership agreement requires us to make quarterly
distributions to our unitholders of all available cash reduced by any amounts of
reserves for commitments and contingencies, including capital and operating
costs and debt service requirements. The value of our common units
and other limited partner interests may decrease in direct correlation with
decreases in the amount we distribute per common unit. Accordingly,
if we experience a liquidity problem in the future, we may not be able to issue
more equity to recapitalize.
Cost
reimbursements to EPCO and its affiliates will reduce cash available for
distribution to our unitholders.
Prior to
making any distribution on our common units, we will reimburse EPCO and its
affiliates for all expenses they incur on our behalf, including allocated
overhead. These amounts will include all costs incurred in managing
and operating us, including costs for rendering administrative staff and support
services to us, and overhead allocated to us by EPCO. The payment of
these amounts could adversely affect our ability to make distributions to our
unitholders. EPCO has sole discretion to determine the amount of
these expenses. In addition, EPCO and its affiliates may provide
other services to us for which we will be charged fees as determined by
EPCO.
Unitholders
may not have limited liability if a court finds that unitholder action
constitutes control of our business.
The
limitations on the liability of holders of limited partner interests for the
obligations of a limited partnership have not been clearly established in some
of the states in which we do business. Unitholders could have
unlimited liability for our obligations if a court or government agency
determined that:
|
§
|
we
were conducting business in a state, but had not complied with that
particular state’s partnership statute;
or
|
|
§
|
unitholders’
right to act with other unitholders to remove or replace our general
partner, to approve some amendments to our partnership agreement or to
take other actions under our partnership agreement constituted “control”
of our business.
|
Unitholders
may have liability to repay distributions.
Under certain circumstances,
unitholders may have to repay amounts wrongfully returned or distributed to
them. Under Section 17-607 of the Delaware Revised Uniform Limited
Partnership Act, we may not make a distribution to our unitholders if the
distribution would cause our liabilities to exceed the fair value of our
assets. Liabilities to partners on account of their partnership
interests and liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted. Delaware law provides that for a period of three years
from the date of an impermissible distribution, limited partners who received
the distribution and who knew at the time of the distribution that it violated
Delaware law will be liable to the limited partnership for the distribution
amount. A purchaser of common units who becomes a limited partner is
liable for the obligations of the transferring limited partner to make
contributions to the partnership that are known to such purchaser of common
units at the time it became a limited partner and for unknown obligations if the
liabilities could be determined from our partnership agreement.
Our
general partner’s interest in us and the control of our general partner may be
transferred to a third-party without unitholder consent.
Our
general partner may transfer its general partner interest to a third-party in a
merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, there is no restriction in
our partnership agreement on the ability of DEP GP or EPO to transfer their
equity interests in our general partner to a third-party. The new
equity owner of our general partner would then be in a position to replace the
board of directors and officers of our general partner with their own choices
and to influence the decisions taken by the board of directors and officers of
our general partner.
Tax
Risks to Common Unitholders
Our
tax treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to a material amount of entity-level
taxation by individual states. If the Internal Revenue Service were to treat us
as a corporation or if we were to become subject to a material amount of
entity-level taxation for state tax purposes, then our cash distributions to our
unitholders would be substantially reduced.
The
anticipated after-tax benefit of an investment in our common units depends
largely on our being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling
from the Internal Revenue Service (“IRS”) on this matter.
If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our income at the corporate tax rate, which is currently a
maximum of 35%. Distributions to our unitholders could generally be
taxed again as corporate distributions, and no income, gains, losses, deductions
or credits could flow through to unitholders. Because a tax could be
imposed upon us as a corporation, our cash available for distribution to our
common unitholders could be substantially reduced. Thus, treatment of
us as a corporation could result in a material reduction in the after-tax return
to our common unitholders, likely causing a substantial reduction in the value
of our common units.
Current
law may change, causing us to be treated as a corporation for federal income tax
purposes or otherwise subjecting us to a material amount of entity-level
taxation. In addition, because of widespread state budget deficits
and other reasons, several states are evaluating ways to enhance state-tax
collections.
If any additional state were
to impose an entity-level tax upon us or our operating subsidiaries, the cash
available for distribution to our common unitholders could be reduced.
The
tax treatment of publicly traded partnerships or an investment in our common
units could be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive
basis.
The present U.S. federal income tax
treatment of publicly traded partnerships, including us, or an investment in our
common units may be modified by administrative, legislative or judicial
interpretation at any time. Any modification to the U.S. federal
income tax laws and interpretations thereof could make it more difficult or
impossible to meet the exception, which we refer to as the qualifying income
exception, for us to be treated as a partnership for U.S. federal income tax
purposes that is not taxable as a corporation, affect or cause us to change our
business activities, affect the tax considerations of an investment in us,
change the character or treatment of portions of our income or adversely affect
an investment in our common units. For example, in response to recent
public offerings of interests in the management operations of private equity
funds and hedge funds, members of Congress are considering substantive changes
to the definition of qualifying income under Section 7704 of the Internal
Revenue Code and changing the treatment of certain types of income earned from
profits or “carried” interests. It is possible that these legislative
efforts could result in changes to the existing U.S. tax laws that affect
publicly traded partnerships, including us. Although we are unable to
predict whether any of these changes or other proposals will ultimately be
enacted and, if so, whether any such changes would be applied retroactively, the
enactment of any such changes could negatively impact the value of an investment
in our common units.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular common unit is transferred.
We prorate our items of income, gain,
loss and deduction between transferors and transferees of our common units each
month based upon the ownership of our common units on the first day of each
month, instead of on the basis of the date a particular common unit is
transferred. The use of this proration method may not be permitted
under existing Treasury Regulations, and, accordingly, our counsel is unable to
opine as to the validity of this method. If the IRS were to challenge
this method or new Treasury Regulations are issued, we may be required to change
the allocation of items of income, gain, loss and deduction among our
unitholders.
A
successful IRS contest of the federal income tax positions we take may adversely
impact the market for our common units, and the costs of any contests will be
borne by our unitholders and our general partner.
The IRS
may adopt positions that differ from the positions we take, even positions taken
with advice of counsel. 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 some or all of 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 our common units
trade. In addition, the costs of any contest with the IRS,
principally legal, accounting and related fees, will result in a reduction in
cash available for distribution to our unitholders and our general partner and
thus will be borne indirectly by our unitholders and our general
partner.
Even
if our common unitholders do not receive any cash distributions from us, they
will be required to pay taxes on their share of our taxable income.
Common
unitholders will be required to pay federal income taxes and, in some cases,
state and local income taxes on their share of our taxable income, whether or
not they receive any cash distributions from us. Our common
unitholders may not receive cash distributions from us equal to their share of
our taxable income or even equal to the actual tax liability resulting from
their share of our taxable income.
Tax
gain or loss on the disposition of our common units could be different than
expected.
If a
common unitholder sells common units, the unitholder will recognize a gain or
loss equal to the difference between the amount realized and the unitholder’s
tax basis in those common units. Prior distributions to a unitholder
in excess of the total net taxable income a unitholder is allocated by us, which
decreases the unitholder’s tax basis in a common unit, will, in effect, become
taxable income to the unitholder if the common unit is sold at a price greater
than the unitholder’s tax basis in that common unit, even if the price the
unitholder receives is less than the unitholder’s original cost. A
substantial portion of the amount realized, whether or not representing gain,
may be ordinary income to a unitholder.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning common units
that may result in adverse tax consequences to them.
Investment in common units by
tax-exempt entities, such as individual retirement accounts (known as IRAs),
other retirement plans and non-U.S. persons raises issues unique to
them. For example, virtually all of our income allocated to
unitholders who are 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 at the highest applicable
effective 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.
We
treat each purchaser of our common units as having the same tax benefits without
regard to the common units purchased. The IRS may challenge this treatment,
which could result in a decrease in the value of our common units.
Because
we cannot match transferors and transferees of common units, we will adopt
depreciation and amortization positions that may not conform to all aspects of
existing Treasury Regulations. A successful IRS challenge to those
positions could decrease the amount of tax benefits available to a common
unitholder. It also could affect the timing of these tax benefits or
the amount of gain from a sale of common units and could have a negative impact
on the value of our common units or result in audit adjustments to the common
unitholder’s tax returns.
Our
common 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 an
investment in our common units.
In
addition to federal income taxes, our common unitholders will likely be subject
to other taxes, such as state and local income 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. Our
common unitholders will likely be required to file state and local income tax
returns and pay state and local income taxes in some or all of these various
jurisdictions. Further, they may be subject to penalties for failure
to comply with those requirements. We own property or conduct
business in Louisiana and Texas. We may own property or conduct
business in other states or foreign countries in the future. It is
the responsibility of each unitholder to file its own federal, state and local
tax returns.
The
sale or exchange of 50% or more of our capital and profits interests during a
twelve-month period will result in the termination of our partnership for
federal income tax purposes.
We will
be considered to have terminated 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.
We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between DEP GP and our unitholders. The
IRS may challenge this treatment, which could adversely affect the value of our
common units.
When we
issue additional common 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 DEP GP. Our 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 DEP GP, which may be
unfavorable to such unitholders. Moreover, under this methodology,
subsequent purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated to our intangible
assets and a lesser portion allocated to our tangible assets. The IRS
may challenge our 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 DEP GP 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 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 the unitholder’s tax returns without the benefit of additional
deductions.
A
unitholder whose common units are loaned to a “short seller” to cover a short
sale of common units may be considered as having disposed of those common
units. If so, he would no longer be treated for tax purposes as a
partner with respect to those common units during the period of the loan and may
recognize gain or loss from the disposition.
Because a common unitholder whose
common units are loaned to a “short seller” to cover a short sale of common
units may be considered as having disposed of the loaned units, he may no longer
be treated for tax purposes as a partner with respect to those common units
during the period of the loan to the short seller and he may recognize gain or
loss from such disposition. Moreover, during the period of the loan
to the short seller, any of our income, gain, loss or deduction with respect to
those common units may not be reportable by the unitholder and any cash
distributions received by the unitholder as to those common units could be fully
taxable as ordinary income. Our counsel has not rendered an opinion
regarding the treatment of a unitholder whose common units are loaned to a short
seller to cover a short sale of common units; therefore, unitholders desiring to
assure their status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable brokerage account
agreements to prohibit their brokers from borrowing their common
units.
None.
On
occasion we are, or our unconsolidated affiliate is, named as a defendant in
legal proceedings relating to our normal business operations, including
regulatory and environmental matters. Although we are insured against
various risks to the extent we believe it is prudent, there is no assurance that
the nature and amount of such insurance will be adequate, in every case, to
indemnify us against liabilities arising from future legal
proceedings. We are not aware of any litigation, pending or
threatened, that we believe is reasonably likely to have a significant adverse
effect on our financial position, results of operations or cash
flows. For detailed information regarding our legal proceedings, see
Note 17 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report, which is incorporated by reference into this Item
3.
Equity
Securities.
Market
Information and Cash Distributions
Our common units are listed on
the NYSE under the ticker symbol “DEP.” As of February 1, 2010, there
were approximately 40 unitholders of record of our common units. The
following table presents the high and low sales prices for our common units
during the periods indicated (as reported by the NYSE Composite Transaction
Tape) and the amount, record date and payment date of the quarterly cash
distributions we paid on each of our common units with respect to such
periods.
|
Cash
Distribution History
|
||||||||||||||
|
Price
Ranges
|
Per
|
Record
|
Payment
|
|||||||||||
|
High
|
Low
|
Unit
|
Date
|
Date
|
||||||||||
|
2008
|
||||||||||||||
|
1st
Quarter
|
$ | 23.65 | $ | 18.29 | $ | 0.4100 |
April
30, 2008
|
May
7, 2008
|
||||||
|
2nd
Quarter
|
21.29 | 18.04 | 0.4200 |
July
31, 2008
|
August
7, 2008
|
|||||||||
|
3rd
Quarter
|
18.96 | 14.91 | 0.4200 |
October
31, 2008
|
November
12, 2008
|
|||||||||
|
4th
Quarter
|
16.99 | 9.68 | 0.4275 |
January
30, 2009
|
February
9, 2009
|
|||||||||
|
2009
|
||||||||||||||
|
1st
Quarter
|
18.07 | 13.55 | 0.4300 |
April
30, 2009
|
May
8, 2009
|
|||||||||
|
2nd
Quarter
|
20.15 | 14.75 | 0.4350 |
July
31, 2009
|
August
7, 2009
|
|||||||||
|
3rd
Quarter
|
20.00 | 15.91 | 0.4400 |
October
30, 2009
|
November
5, 2009
|
|||||||||
|
4th
Quarter
|
24.19 | 19.19 | 0.4450 |
January
29, 2010
|
February
5, 2010
|
|||||||||
The
quarterly cash distributions per unit shown in the preceding table correspond to
cash flows for the quarters indicated. The actual cash distributions
(i.e., the payments made to our common unitholders) occur within 45 days after
the end of such quarter. We expect to fund our quarterly cash
distributions to common unitholders primarily with cash provided by operating
activities. For additional information regarding our cash flows from
operating activities, see “Liquidity and Capital Resources” included under Item
7 of this annual report. Although the payment of cash distributions
is not guaranteed, we expect to continue to pay comparable cash distributions in
the future.
On
December 8, 2008, we issued 37,333,887 Class B units to EPO in connection with
the DEP II drop down transaction. On February 9, 2009, the
Class B units received a cash distribution of $0.1115 per unit for the
distribution that Duncan Energy Partners paid with respect to the fourth quarter
of 2008, which represented the regular quarterly distribution pro-rated for the
24-day period from December 8, 2008, the closing date of the DEP II drop down
transaction, to December 31, 2008. These units automatically
converted on a one-for-one basis to common units on February 1,
2009.
Recent
Sales of Unregistered Securities
There were no sales of unregistered
equity securities during 2009 that have not been previously
reported.
Securities
Authorized for Issuance Under Equity Compensation Plans
As of December 31, 2009, there were no
effective long-term incentive plans of EPCO under which our common units are
authorized for issuance. However, the 2010 Duncan Energy Partners
L.P. Long-term Incentive Plan (“2010 Plan”) and DEP Unit Purchase Plan (“EUPP”)
were approved by written consent of a holder of a majority of our common units
on December 30, 2009 and became effective upon filing of a registration
statement on Form S-8 with the SEC in February 2010. For more
information about the 2010
Plan and
EUPP, see Item 9B “Other Information” and Note 5 of the Notes to Consolidated
Financial Statements included in Item 8 of this annual report.
Issuer
Purchases of Equity Securities
In June 2009, we completed a
common unit offering of 8,000,000 units at an average price paid per unit of
$15.36 that generated net proceeds of approximately $122.9 million after
underwriting discounts and other expenses. In July 2009, the
underwriters of this offering exercised a portion of their 30-day option to
purchase an additional 943,400 common units at an average price per unit of
$15.36, which generated approximately $14.5 million of additional net
proceeds. The total net proceeds from this offering, including the
overallotment amount, were used to repurchase an equal number of our common
units beneficially owned by EPO: 8,000,000 units were repurchased in June 2009
and 943,400 units were repurchased in July 2009. The repurchased
common units were subsequently cancelled.
The following table presents selected
historical consolidated financial data of our partnership. This information has
been derived from and should be read in conjunction with our audited financial
statements included under Item 8 within this annual
report. Information regarding our consolidated results of operations
and liquidity and capital resources can be found under Item 7 within this annual
report. As presented in the table, amounts are in millions (except
per unit data).
|
For
the Year Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Operating
Results Data:
|
||||||||||||||||||||
|
Revenues
|
$ | 979.3 | $ | 1,598.1 | $ | 1,220.3 | $ | 1,263.0 | $ | 1,257.8 | ||||||||||
|
Net
income
|
45.8 | 55.3 | 23.6 | 51.7 | 30.1 | |||||||||||||||
|
Net
loss (income) attributable to noncontrolling interest (1)
|
45.3 | (7.4 | ) | (20.0 | ) | -- | -- | |||||||||||||
|
Net
income attributable to Duncan Energy Partners
|
91.1 | 47.9 | 3.6 | 51.7 | 30.1 | |||||||||||||||
|
Allocation
of net income attributable to Duncan Energy Partners L.P.:
|
||||||||||||||||||||
|
Limited
partners of Duncan Energy Partners
|
$ | 90.5 | $ | 27.8 | $ | 18.8 | n/a | n/a | ||||||||||||
|
General
partner of Duncan Energy Partners
|
0.6 | 0.5 | 0.4 | n/a | n/a | |||||||||||||||
|
Former
owner of DEP II Midstream Businesses
|
n/a | 19.6 | (20.6 | ) | (3.7 | ) | (9.0 | ) | ||||||||||||
|
Former
owner of DEP I Midstream Businesses
|
n/a | n/a | 5.0 | 55.3 | 39.1 | |||||||||||||||
|
Basic
and diluted earnings per unit
|
$ | 1.57 | $ | 1.22 | $ | 0.93 | n/a | n/a | ||||||||||||
|
Cash
distributions per common unit (2)
|
$ | 1.75 | $ | 1.68 | $ | 1.46 | n/a | n/a | ||||||||||||
|
Financial
position data:
|
||||||||||||||||||||
|
Total
assets (3)
|
$ | 4,770.8 | $ | 4,594.7 | $ | 3,983.3 | $ | 3,798.4 | $ | 3,688.9 | ||||||||||
|
Long-term
debt (4)
|
457.3 | 484.3 | 200.0 | n/a | n/a | |||||||||||||||
|
Former
owner’s equity in DEP II Midstream Businesses (5)
|
n/a | n/a | 2,880.1 | 2,853.8 | 2,903.6 | |||||||||||||||
|
Former
owner’s equity in DEP I Midstream Businesses (5)
|
n/a | n/a | n/a | 725.8 | 527.8 | |||||||||||||||
|
Equity
(6)
|
4,136.9 | 3,844.2 | 669.9 | n/a | n/a | |||||||||||||||
|
Total
common units outstanding (7)
|
57.7 | 57.7 | 20.3 | n/a | n/a | |||||||||||||||
|
(1)
Represents
EPO’s share of the earnings of the DEP I and DEP II Midstream Businesses
following the drop down of each set of businesses to Duncan Energy
Partners. The DEP I drop down transaction was effective February 1,
2007 for financial accounting and reporting purposes. The DEP II drop
down transaction was effective December 8, 2008.
(2)
Represents
cash distributions declared by Duncan Energy Partners since its initial
public offering in February 2007.
(3)
Total
assets have increased since our initial public offering due to capital
spending.
(4)
Represents
our Revolving Credit Facility and Term Loan Agreement, as applicable, for
the periods in which Duncan Energy Partners had borrowings outstanding
under each agreement.
(5)
Represents
the net assets of the combined DEP I or DEP II Midstream Businesses (as
applicable) prior to the date they were contributed to Duncan Energy
Partners.
(6)
Represents
the noncontrolling interest in subsidiaries, limited and general partner
capital accounts and related accumulated other comprehensive income of
Duncan Energy Partners since February 2007.
(7)
The
amount presented for December 31, 2008 includes 37.3 Class B units that
converted to common units on February 1, 2009.
|
||||||||||||||||||||
For
the years ended December 31, 2009, 2008 and 2007.
The following information should be
read in conjunction with our consolidated financial statements and our
accompanying notes included under Item 8 within this annual
report. Our discussion and analysis includes the
following:
|
§
|
Cautionary
Note Regarding Forward-Looking
Statements.
|
|
§
|
Overview
of Business.
|
|
§
|
Basis
of Financial Statement
Presentation.
|
|
§
|
Supplemental
Selected Financial Information of Duncan Energy Partners L.P. – Discusses
financial information and sources and uses of cash for Duncan Energy
Partners L.P. on a standalone
basis.
|
|
§
|
Significant
Recent Developments – Discusses significant developments during the year
ended December 31, 2009 and through the date of this
filing.
|
|
§
|
General
Outlook for 2010.
|
|
§
|
Results
of Operations – Discusses material year-to-year variances in our
Statements of Consolidated
Operations.
|
.
|
§
|
Liquidity
and Capital Resources – Addresses available sources of liquidity and
capital resources and includes a discussion of our capital spending
program.
|
|
§
|
Critical
Accounting Policies and Estimates.
|
|
§
|
Other
Items – Includes information related to contractual obligations,
off-balance sheet arrangements and all other
matters.
|
Our
financial statements have been prepared in accordance with U.S. generally
accepted accounting principles (“GAAP”).
Cautionary
Note Regarding Forward-Looking Statements
This discussion contains various
forward-looking statements and information that are based on our beliefs and
those of our general partner, as well as assumptions made by us and information
currently available to us. When used in this document, words such as
“anticipate,” “project,” “expect,” “plan,” “seek,” “goal,”
“estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,”
“potential” and similar expressions and statements regarding our plans and
objectives for future operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A of this annual report. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove incorrect, our
actual results may vary materially from those anticipated, estimated, projected
or expected. You should not put undue reliance on any forward-looking
statements. The forward-looking statements in this annual report speak only as
of the date hereof. Except as required by federal and state
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or any other reason.
Overview of Business
Duncan Energy Partners is a publicly
traded Delaware limited partnership, the common units of which are listed on the
NYSE under the ticker symbol “DEP.” Duncan Energy Partners was formed
in September 2006 and did not own any assets prior to February 5, 2007, which
was the date it completed its initial public offering and acquired controlling
interests in the DEP I Midstream Businesses from EPO. The business
purpose of Duncan Energy Partners is to acquire, own and operate a diversified
portfolio of midstream energy assets and to support the growth objectives of EPO
and other affiliates under common control. Duncan Energy Partners is
engaged in the business of: (i) NGLs transportation, fractionation and
marketing; (ii) storage of NGL and petrochemical products; (iii) transportation
of petrochemical products; and (iv) the gathering, transportation, marketing and
storage of natural gas.
Duncan Energy Partners was owned 99.3%
by its limited partners and 0.7% by its general partner, DEP GP, at December 31,
2009. EPO beneficially owned approximately 58.6% of our common units
and 100% of DEP GP at December 31, 2009. DEP GP is responsible as
general partner for managing our business and operations. EPCO
provides all of our employees and certain administrative services to
us.
Our relationship with EPO is one of our
principal business advantages. Our assets connect to various
midstream energy assets of EPO and form integral links within EPO’s value chain
of assets. We believe that the operational significance of our assets
to EPO, as well as the alignment of our respective economic interests in these
assets, will result in a collaborative effort between us and EPO to promote the
operational efficiency of our assets and maximize their value. See
Note 15 of the Notes to Consolidated Financial Statements included under Item 8
within this annual report for additional information regarding our extensive and
ongoing relationships with EPO and EPCO.
DEP
I Drop Down
On
February 5, 2007, EPO contributed to us a 66% controlling equity interest in
each of the DEP I Midstream Businesses in a drop down
transaction. EPO retained the remaining 34% noncontrolling equity
interest in each of these businesses. As consideration for these
equity interests, we paid $459.5 million in cash and issued 5,351,571 common
units to EPO. The cash portion of this consideration was financed
with $198.9 million in borrowings under our Revolving Credit Facility and $260.6
million of the $290.5 million of net proceeds from our initial public
offering. See Item 1 and 2 within this annual report for a
description of the assets and operations of the DEP I Midstream
Businesses.
DEP
II Drop Down
On
December 8, 2008, EPO contributed to us the following controlling equity
interests in a second drop down transaction: (i) a 66% general partner interest
in Enterprise GC, (ii) a 51% general partner interest in Enterprise Intrastate
and (iii) a 51% membership interest in Enterprise Texas. As
consideration for these equity interests, we paid $280.5 million in cash and
issued 37,333,887 Class B units to EPO (which automatically converted on a
one-for-one basis to common units in February 2009). The cash portion
of this consideration was financed with $280.0 million in borrowings under our
Term Loan Agreement and $0.5 million of net proceeds from an equity offering to
EPO. The market value of the Class B units at the time of issuance
was approximately $449.5 million. See Item 1 and 2 within this annual
report for a description of the assets and operations of the DEP II Midstream
Businesses.
Noncontrolling
Interests
For detailed information regarding
EPO’s noncontrolling interest in the DEP I and DEP II Midstream Businesses, see
Note 13 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
Basis of Financial Statement
Presentation
See Note 1 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual report
for information regarding the basis for presentation of our general purpose
financial statements. Such information is incorporated by reference
into this Item 7 discussion.
Supplemental
Selected Financial Information of Duncan Energy Partners L.P.
We are providing the following selected
financial information to assist investors and other users of our financial
statements in understanding the principal sources and uses of cash flows of
Duncan Energy Partners L.P. on a standalone basis. Duncan Energy
Partners L.P. has no operations apart from its investing activities and
indirectly overseeing the management of the DEP I and DEP II Midstream
Businesses.
The primary sources of cash flow for
Duncan Energy Partners L.P. are the cash distributions it receives from the DEP
I and DEP II Midstream Businesses. The primary cash requirements of
Duncan Energy Partners are for general and administrative costs, debt service
and distributions to partners. The amount of cash distributions that
Duncan Energy Partners L.P. is able to pay its unitholders may fluctuate based
on the level of distributions it receives from its operating
subsidiaries. Factors such as capital contributions, debt service
requirements, general and administrative costs, reserves for future
distributions and other cash reserves established by the board of directors of
our general partner (the “Board”) may also affect the distributions Duncan
Energy Partners L.P. makes to its unitholders.
For purposes of this presentation, we
have provided information pertaining to the DEP I Midstream Businesses apart
from those of the DEP II Midstream Businesses. Amounts presented for
fiscal 2007 represent the eleven-month period from our initial public offering
(effective February 1, 2007) through December 31, 2007. Amounts
presented for the DEP II Midstream Businesses for fiscal 2008 represent the
period from December 8, 2008 to December 31, 2008.
| Eleven |
|
||||||||||||
|
Twelve
Months
|
Months |
|
|||||||||||
| Ended December 31, |
|
||||||||||||
|
2009
|
2008 |
|
2007 |
|
|||||||||
|
(dollars
in millions)
|
|||||||||||||
|
Selected
income statement information:
|
|||||||||||||
|
Equity in income - DEP I Midstream Businesses
|
$ | 44.9 | $ | 37.2 | $ | 30.0 | |||||||
|
Equity in income - DEP II Midstream Businesses
|
$ | 60.1 | $ | 4.5 | $ | -- | |||||||
|
General and administrative costs
|
$ | 0.4 | $ | 1.4 | $ | 1.5 | |||||||
|
Interest expense
|
$ | 13.5 | $ | 12.0 | $ | 9.3 | |||||||
|
Net income attributable to Duncan Energy Partners L.P.
|
$ | 91.1 | $ | 28.3 | $ | 19.2 | |||||||
|
Selected
balance sheet information at each period end:
|
|||||||||||||
|
Investments in DEP I Midstream Businesses
|
$ | 510.2 | $ | 512.7 | $ | 502.7 | |||||||
|
Investments in DEP II Midstream Businesses
|
$ | 709.7 | $ | 730.5 | $ | -- | |||||||
|
Long-term debt
|
$ | 457.3 | $ | 484.3 | $ | 200.0 | |||||||
|
Partners’ equity
|
$ | 761.4 | $ | 752.8 | $ | 314.6 | |||||||
The following table presents the amount
of distributions paid by each group of businesses with respect to each
period.
|
Eleven
|
||||||||||||
|
Twelve
Months
|
Months
|
|||||||||||
|
Ended
December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(dollars
in millions)
|
||||||||||||
|
Distributions
paid to Duncan Energy Partners L.P.
|
||||||||||||
|
with
respect to each period from:
|
||||||||||||
|
DEP
I Midstream Businesses
|
$ | 49.2 | $ | 93.7 | $ | 115.3 | ||||||
|
DEP
II Midstream Businesses
|
$ | 86.5 | $ | 5.6 | $ | -- | ||||||
Generally, to the extent that the DEP
II Midstream Businesses collectively generate cash sufficient to pay
distributions to EPO and us, such cash will be distributed first to us (the
“Tier I distribution,” based on our $730.0 million aggregate investment) and
then to EPO (the “Tier II distribution”), in amounts sufficient to generate an
annualized return to both owners based on their respective
investments. Distributions in excess of these amounts (the “Tier III
distributions”) will be distributed 98% to EPO and 2% to
us.
The initial annualized return rate for
2009 was 11.85%, and was determined by EPO and us based on our estimated
weighted-average cost of capital at December 8, 2008, plus 1.0%. The
annualized return rate increases by 2.0% on January 1 of each
year. As a result, the annualized return rate for 2010 will be
12.087%. If we participate in an expansion capital project involving
the DEP II Midstream Businesses, we may request an incremental adjustment to the
then-applicable annualized return rate to reflect our weighted-average cost of
capital associated with such contribution.
The annualized return rate is applied
to each party’s aggregate investment (or “Distribution Base”) in the DEP II
Midstream Businesses. To the extent that we and/or EPO make capital
contributions to fund expansion capital projects involving the DEP II Midstream
Businesses, the Distribution Base of the contributing member will be increased
by that member’s capital contribution at the time such contribution is
made. At December 8, 2008 and December 31, 2009, our Distribution
Base was $730.0 million. EPO’s Distribution Base was $452.1 million
and $817.9 million at December 8, 2008 and December 31, 2009,
respectively. The increase in EPO’s Distribution Base is the result
of its decision to fund 100% of the expansion capital projects of the DEP II
Midstream Businesses since December 8, 2008. We have not yet
participated in the expansion capital project spending of the DEP II Midstream
Businesses, although we may elect to invest in existing or future expansion
projects at a later date.
We and EPO received $86.5 million and
$29.8 million, respectively, in cash distributions from the DEP II Midstream
Businesses for the twelve months ended December 31, 2009. The $86.5
million (or, approximately, $21.6 million each quarter) received by us with
respect to 2009 represents the annualized return rate for 2009 of 11.85%
multiplied by our Distribution Base of $730.0 million. As a result,
we received our expected Tier I distributions for the period. Based
on EPO’s Distribution Base throughout 2009, it was entitled to $83.4 million of
Tier II distributions, of which it received only $29.8 million. No
Tier III distributions were paid by the DEP II Midstream Businesses with respect
to 2009.
Net income (or loss) of the DEP II
Midstream Businesses is first allocated to us and EPO based on each entity’s
percentage interest of 22.6% and 77.4%, respectively, and then in a manner that
in part follows the cash distributions paid by (or contributions made to) each
DEP II Midstream Business. Under our income sharing arrangement with
EPO, we are allocated additional income (in excess of our percentage interest)
to the extent that the cash distributions we receive (or contributions made)
exceed the amount we would have been entitled to receive (or required to fund)
based solely on our percentage interest. This additional earnings
allocation to us reduces the amount of income allocated to EPO by an equal
amount and may result in EPO being allocated a loss when we are allocated
income. It is our expectation that EPO will be allocated a loss by
the DEP II Midstream Businesses until such time as expansion capital projects
such as the Sherman Extension and Trinity River Lateral realize their income and
cash flow potential. Our participation in the expected future
increase in cash flow from such projects is limited (beyond our annualized
return amount) to 2% of such upside, with EPO receiving 98% of the
benefit.
For information regarding the non-cash
depreciation, amortization and accretion amounts of the DEP I and DEP II
Midstream Businesses on a 100% basis, see Note 19 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report.
Significant
Recent Developments
The following information highlights
our significant recent developments since January 1, 2009 through the date of
this filing:
Duncan
Energy Partners and Enterprise Products Partners Announce Extension
of
Acadian
Gas System into Haynesville Shale Supply Basin
In October 2009, we and EPO, announced
plans for our jointly owned Acadian Gas System to extend its Louisiana
intrastate natural gas pipeline system into northwest Louisiana to provide
producers in the rapidly expanding Haynesville Shale natural gas supply basin
with access to additional markets through connections with the Acadian Gas
System in south Louisiana and nine major interstate natural gas pipelines
(“Haynesville Extension”). The Haynesville Shale producing area is
believed to cover approximately 2 million acres in northwest Louisiana, almost
all of which is under lease. Production from the approximately 200
wells drilled to date is estimated at more than 1 Bcf/d. Over 400
locations are in various stages of drilling and completion with approximately
150 rigs now working in the region.
As
currently designed, the Haynesville Extension will have the potential capacity
to transport up to 2.1 Bcf/d of natural gas from the Haynesville area through a
249-mile pipeline that will connect with our existing Acadian Gas
System. The pipeline is expected to be in service during the third
quarter of 2011.
The
Acadian Gas System serves major natural gas markets along the Mississippi River
corridor between Baton Rouge and New Orleans and has the ability to make
physical deliveries into the Henry Hub. The Haynesville Extension
will also have interconnects with major interstate pipelines including Florida
Gas, Texas Eastern, Transco, Sonat, Columbia Gulf, Trunkline, ANR, Tennessee Gas
and Texas Gas. Together with the capacity of the existing Acadian Gas
System, the extension project will provide approximately 6.2 Bcf/d of redelivery
capacity into an estimated 12 Bcf/d of available downstream pipeline takeaway
capacity. Initially, the project will connect to nine Haynesville
Shale producer locations in DeSoto and Red River parishes.
Along
with providing much needed natural gas takeaway capacity for growing Haynesville
production, the new pipeline is expected to provide shippers the opportunity to
benefit from additional pricing points and diverse service options and access to
the south Louisiana marketplace. For producers, the more flexible
contracting options associated with an intrastate pipeline environment is
expected to help facilitate a seamless transaction for the producer from the
field to the end user.
Currently,
we own a 66% equity interest in the entities that own the Acadian Gas System,
with EPO owning the remaining 34% equity interest. We are in
discussions with EPO regarding the funding and related aspects of the
Haynesville Extension project.
Service
Begins on Sherman Extension Pipeline
In late February 2009, we and EPO
announced that construction had been completed on the 173-mile Sherman Extension
expansion of our Texas Intrastate System, which extends through the heart of the
prolific Barnett Shale natural gas production basin of north
Texas. The completion of the Sherman Extension adds 1.2 Bcf/d of
incremental natural gas takeaway capacity from the region, while providing
producers in the Barnett Shale, and as far away as the Waha area of west Texas,
with greater flexibility to reach the most attractive natural gas
markets. The Texas Intrastate System is part of our Natural Gas
Pipelines & Services business segment through interconnections with
pipelines that serve the Midwest and Northeast regions of the United
States.
Initially, the Sherman Extension began
providing intrastate service, and its subsequent NGPA 311 transportation was in
very limited service due to pipeline integrity issues on the connecting
third-party take-away pipeline, the Gulf Crossing Pipeline owned by Boardwalk
Pipeline Partners, LP. The Gulf Crossing Pipeline began ramping up
its operations on August 1, 2009. As a result, the Sherman Extension
started billing its demand charges at 95% of its contracted volumes, which are
950 MMcf/d. Effective September 1, 2009, the Sherman Extension
started billing demand charges on 100% of contracted volumes, irrespective of
actual transportation volumes. We are currently flowing approximately
700 MMcf/d. The demand charges are approximately $5.0 million a
month.
Registration
Statements and Equity Offerings
In connection with our June 2009 equity
offering, we issued 8,943,400 common units and generated net proceeds of
approximately $137.4 million after underwriting discounts and other offering
expenses. The net proceeds were used to repurchase an equal number of
our common units beneficially owned by EPO. The repurchased common
units were subsequently cancelled.
In December 2009, we filed a
registration statement with the Securities Exchange Commission (“SEC”)
authorizing the issuance of up to 2,000,000 common units in connection with a
distribution reinvestment plan (“DRIP”). Plan participants may
purchase our common units at a discount ranging from 0% to 5% (currently set at
5%), which will be set from time to time by us.
In
February 2010, we filed a registration statement with the SEC authorizing the
issuance of up to 1,000,000 common units in connection with an employee unit
purchase plan and a long-term incentive plan that became effective on February
11, 2010. See Item 9B for additional information regarding the
approval of these plans.
General
Outlook for 2010
Commercial
Outlook
We provide midstream energy services to
producers and consumers of natural gas, NGLs and certain
petrochemicals. Factors that can affect the demand for our services
include global and U.S. economic conditions, the demand for energy, the market
price of energy, the cost to develop natural gas and crude oil reserves in the
U.S. and the cost and availability of capital to energy companies to invest in
drilling activities.
The
global economic contraction that began in late 2007 appeared to show signs of
stabilizing in the second half of 2009 with most of the twenty largest developed
economies (“G20”) reporting quarter- over-quarter growth in real gross domestic
product (“GDP”) beginning in the third quarter of 2009. However,
approximately 65 percent of the G20 were still reporting year-over-year
contraction in real GDP in 2009. The United States reported
quarter-over-quarter real GDP growth of 2.2 percent and 5.7 percent for the
third and fourth quarters of 2009, respectively, after five quarters of
contraction in real GDP since the beginning of 2008. Real GDP growth
for 2009 compared to 2008 was 0.1 percent.
Impacted
by general economic conditions and price shock-induced conservation by
consumers, U.S. demand for petroleum products and natural gas (as reported by
the U.S. Energy Information Administration) for the first ten months of 2009
decreased approximately 5.4 percent and 2.1 percent, respectively, from the same
periods in 2008 and by approximately 11 percent and 1.5 percent, respectively,
from the first ten months of 2007. Likewise, U.S. demand for
petroleum products for transportation purposes (e.g. motor gasoline, distillate,
jet fuel) for the first ten months of 2009 declined by 2.7 percent and 6.3
percent compared to the first ten months of 2008 and 2007,
respectively. The rate of decline in U.S. demand for petroleum
products since mid-2009 appears to be moderating and demand for natural gas
since mid-2009 has increased by 1.5 percent compared to the same period in
2008.
Energy prices have generally rebounded
with the recovery in demand, economic growth and stability in the capital
markets. The average prices for West Texas Intermediate crude oil and
Mont Belvieu ethane for December 2009 increased by approximately 82 percent and
120 percent, respectively, from December 2008; while natural gas at the Henry
Hub in December 2009 decreased by 8 percent from December
2008. Notably, there has been a substantial change in the price
relationship between natural gas and crude oil. In December 2008,
natural gas was priced at 81 percent of crude oil on an energy equivalent basis
compared to 41 percent in December 2009. We believe changes in the
price relationships of crude oil and crude oil derivatives to natural gas and
NGLs in the past year could lead to a long-term structural change in feedstock
selection by the petrochemical industry.
During
2009 and the beginning of 2010, natural gas and NGLs have a significant price
advantage over more costly crude oil and crude oil derivatives (such as
naphtha). This has been primarily driven by (i) a decline in global
crude oil production; (ii) more government-held acreage being off limits to
non-sovereign energy companies; (iii) geopolitical risk; (iv) growing demand for
crude oil by China and other developing countries; (v) the globalization of
natural gas prices with more LNG facilities becoming operational; and (vi) the
technological breakthroughs around the development of natural gas shale resource
basins that have decreased finding and development costs.
For
ethylene producers, the largest consumers of NGLs, this has meant that ethane
and propane were their most consistently profitable feedstocks in 2009 and are
forecasted to be so in 2010. This feedstock cost advantage and a weak
U.S. dollar provided U.S. ethylene producers with a competitive advantage
globally, especially relative to naphtha crackers in Europe and
Asia. Per industry publications, approximately 24% of 2009 aggregate
domestic production of high density polyethylene (“HDPE”), low density
polyethylene (“LDPE”) and PVC were for the export market.
U.S.
ethylene producers responded by maximizing the use of NGLs as a feedstock,
rationalizing some of their facilities and investing capital to modify their
furnaces to crack more NGLs. The U.S. ethylene industry consumed
almost 1.3 MMBbls/d of NGL feedstocks in December 2009, an 81 percent increase
over 700 MBPD of NGLs consumed in December 2008. We estimate domestic
crackers are in the process of adding approximately 100 MBPD of new capacity to
crack ethane and propane through modifications to their existing
facilities. Certain international ethylene crackers have reacted to
the NGL feedstock cost advantage by importing propane to displace crude oil
derivatives to feed their heavy crackers, including propane produced in the
U.S.
Export
ethylene derivative demand remains strong in early 2010, but is expected to
moderate as Middle East production increases later this
year. Chemical margins in the U.S. are also forecasted to compress
due to increased competition, but overall demand for domestically produced
ethylene is expected to decline only by approximately 1.5% to 48.3 billion
lbs/year in 2010 and then increase 2.3% to 49.4 billion lbs/year in
2011. With the global recession abating, domestic demand is expected
to increase, consuming the production that was sold into the export markets in
2008 and 2009.
Strong
end user demand for NGLs and increases in NGL-rich natural gas production are
expected to (i) keep our NGL fractionators, pipelines and storage facilities
operating at high utilization rates and (ii) provide us with opportunities to
invest capital to build new natural gas gathering and NGL pipeline
facilities.
Natural
gas prices have significantly declined from a peak of over $13.00 per MMBtu in
mid-2008 to $5.35 per MMBtu in December 2009. This price decrease
coupled with the residual impact of a higher cost of capital for certain energy
companies has generally resulted in energy companies reducing their drilling
capital expenditure budgets. This has led to a substantial decrease
in the number of rigs drilling for natural gas in the U.S., declining from a
peak of 1,606 rigs in August 2008 to a low of 665 rigs in July 2009 as natural
gas prices approached a low of $1.88 per MMBtu in September 2009. The
natural gas rig count has since rebounded to 878 rigs at the beginning of
February 2010. Even though the total natural gas rig count has
dropped by almost half, the substantial efficiencies of horizontal drilling in
the non-conventional and shale resource basins have allowed producers to
maintain overall natural gas deliverability. As a result, rig count
is not necessarily a reliable indicator of the level of future natural gas
production. The rig count has increased in the developing Haynesville
Shale, Marcellus Shale and Eagle Ford Shale areas where producers are drilling
to hold recently executed leases. Generally, rig counts remain
significantly below peak levels in areas with conventional natural gas reserves
and areas where producers have leases held by production.
In Texas, the rig count at the end of
2009 was 50 percent below peak levels during 2008. Since the end of
2009, the rig count in Texas has increased 13 percent. The rig count
in the Barnett Shale area at the end of 2009 was approximately 55 percent below
peak levels. While the Barnett Shale has a significant amount of
undeveloped natural gas reserves at relatively low finding costs, much of the
acreage under lease is held by production. Certain energy companies
that were active in the Barnett Shale have elected to
reallocate
a portion of their capital resources in the near term to drill wells in the
Haynesville Shale in northwest Louisiana, the Marcellus Shale in Pennsylvania
and West Virginia, and the Eagle Ford Shale in south Texas to secure recently
acquired leases that are not held by production. Despite the lower
rig count in the Barnett Shale and certain other areas of Texas, we expect
transportation volumes on our Texas Intrastate System to increase by up to 10
percent in 2010 with volume growth principally attributable to a full year of
operations for the Sherman Extension pipeline and the commencement of operations
on the Trinity River Lateral pipeline during the third quarter of
2010. Both of these pipelines serve the Barnett Shale
region.
South
Texas has seen an increase in drilling activity attributable to the development
of the Eagle Ford Shale, which runs parallel to the Texas Gulf Coast and
adjacent to our Texas Intrastate System. We have completed several
small pipeline projects that enable us to gather and transport up to 300 MMcf/d
of new natural gas production from the Eagle Ford Shale. Generally,
energy companies have had early success in the Eagle Ford Shale and several have
indicated they plan to accelerate their drilling programs. Production
associated with this region includes crude oil, NGL-rich natural gas and lean
natural gas. We believe there may be opportunities for us to invest
capital to incrementally expand our natural gas pipeline and storage facilities
and NGL pipeline and fractionation facilities to facilitate production growth
from this region.
The rig
count in Louisiana has increased 14 percent since the end of 2008 primarily due
to development activities in the Haynesville Shale area of northwest
Louisiana. Based on industry success, natural gas production from
this region is expected to grow rapidly over the next several
years. In the fourth quarter of 2009, we announced that seven energy
companies had executed long-term agreements to support the Haynesville Extension
expansion of our Acadian Gas System. The Haynesville Extension is a
249-mile, 42-inch pipeline designed to transport up to 2.1
Bcf/d. Construction of the pipeline will begin in 2010 and is
scheduled to be completed by the end of the third quarter of 2011.
Liquidity
Outlook
The debt
and equity capital markets have significantly improved since the beginning of
2009. The cost of our term debt and equity capital has generally
declined to pre-financial crisis levels. The availability of term
debt and equity capital has also improved. The availability of credit
commitments from most banks has also improved from a year ago; however, the cost
of new bank debt is significantly higher than pre-crisis levels (by
approximately 2 percent on borrowed money) and the term of bank capital is
generally limited to no more than three years.
Our $300
million Revolving Credit Facility and $282.3 million Term Loan Agreement mature
in February and December of 2011, respectively. While we currently
believe our credit cost under new bank facilities could increase by
approximately 2.0 to 2.5 percent on borrowed money, we believe we will have
sufficient liquidity and access to capital markets to refinance these
facilities. Based on amounts outstanding under these facilities at
December 31, 2009, on an annual basis, we estimate the increase in our credit
costs under similar bank facilities currently available in the market could
range from approximately $9.0 million to $11.5 million.
In 2007,
we executed derivative instruments with an aggregate notional amount of $175
million to reduce our exposure to changes in the 1-month London Interbank
Offered Rate (“LIBOR”) (which is a part of the cost of our bank credit
facility). Under these derivative instruments, our counterparties pay
us the 1-month LIBO rate in effect on the periodic reset date and we pay our
counterparties an average fixed rate of 4.62 percent. In 2009, our
aggregate net payments to counterparties under these derivative instruments and
corresponding increase in interest expense was approximately $6.5
million. These derivative instruments expire in September
2010. In the near term, the expiration of these derivative
instruments should reduce our future interest expense; however, upon
termination, 100 percent of our debt will be subject to changes in the 1-month
LIBO rate.
The U.S. government is expected to run
substantial annual budget deficits, exceeding a trillion dollars that will
require a corresponding issuance of debt by the U.S. treasury from 2010 through
2013.
The
interest rate on U.S. Treasury debt has an impact on the cost of our
debt. At this time, we are uncertain what the impact of the large
issuance of U.S. Treasury debt and the prevailing economic and capital market
conditions will have on the cost and availability of capital.
We expect
our proactive approach to funding capital spending and other partnership needs,
combined with sufficient trade credit to operate our businesses efficiently, and
available borrowing capacity under our credit facilities, to provide us with a
foundation to meet our anticipated liquidity and capital requirements in
2010. We also believe that we will be able to access the capital
markets in 2010 to maintain financial flexibility.
Results
of Operations
We have three reportable business
segments: Natural Gas Pipelines & Services; NGL Pipelines & Services;
and Petrochemical Services. Our business segments are generally
organized and managed according to the type of services rendered (or
technologies employed) and products produced and/or sold.
We
evaluate segment performance based on the non-GAAP financial measure of gross
operating margin. Gross operating margin (either in total or by
individual segment) is an important performance measure of the core
profitability of our operations. This measure forms the basis of our
internal financial reporting and is used by management in deciding how to
allocate capital resources among business segments. We believe that
investors benefit from having access to the same financial measures that
management uses in evaluating segment results. The GAAP financial
measure most directly comparable to total segment gross operating margin is
operating income.
We define
total segment gross operating margin as operating income before:
(i) depreciation, amortization and accretion expense; (ii) non-cash
consolidated asset impairment charges; (iii) gains and losses from asset
sales and related transactions; and (iv) general and administrative
costs. Gross operating margin by segment is calculated by subtracting
segment operating costs and expenses (net of the adjustments noted above) from
segment revenues, with both segment totals before the elimination of any
intersegment and intrasegment transactions. In accordance with GAAP,
intercompany accounts and transactions are eliminated in
consolidation. Gross operating margin is exclusive of other income
and expense transactions, provision for income taxes, extraordinary charges and
the cumulative effect of changes in accounting principles. Gross
operating margin is presented on a 100% basis before the allocation of earnings
to noncontrolling interests.
We
include equity earnings from Evangeline in our measurement of segment gross
operating margin and operating income. Our equity investment in
Evangeline is a vital component of our business strategy and important to the
operations of Acadian Gas. This method of operation enables us to
achieve favorable economies of scale relative to the level of investment and
business risk assumed versus what we could accomplish on a stand-alone
basis. Evangeline’s operations complement those of Acadian
Gas. As circumstances dictate, we may increase our ownership interest
in Evangeline or make other equity method investments.
Selected
Volumetric Data
The following table presents average
throughput and fractionation volumes for our principal pipelines and
facilities. These statistics are presented in total for each asset
(or asset group) irrespective of ownership interest (i.e., on a 100% basis),
with the exception of pipeline throughput volumes for Evangeline (a component of
the Acadian Gas System), which we report on a net basis to our ownership
interest.
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Natural
Gas Pipelines & Services, net:
|
||||||||||||
|
Natural
gas throughput volumes (BBtus/d)
|
||||||||||||
|
Texas
Intrastate System
|
3,902 | 4,021 | 3,550 | |||||||||
|
Acadian
Gas System:
|
||||||||||||
|
Transportation
volumes
|
436 | 378 | 416 | |||||||||
|
Sales
volumes (1)
|
320 | 331 | 308 | |||||||||
|
Total
natural gas throughput volumes
|
4,658 | 4,730 | 4,274 | |||||||||
|
NGL
Pipelines & Services, net:
|
||||||||||||
|
NGL
throughput volumes (MBPD)
|
||||||||||||
|
South
Texas NGL System - Pipelines
|
109 | 126 | 124 | |||||||||
|
NGL
fractionation volumes (MBPD)
|
||||||||||||
|
South
Texas NGL System - Fractionators
|
77 | 80 | 72 | |||||||||
|
Petrochemical
Services, net:
|
||||||||||||
|
Propylene
throughput volumes (MBPD)
|
||||||||||||
|
Lou-Tex
Propylene Pipeline
|
21 | 25 | 25 | |||||||||
|
Sabine
Propylene Pipeline
|
9 | 10 | 12 | |||||||||
|
Total
propylene throughput volumes
|
30 | 35 | 37 | |||||||||
|
(1)
Includes
average net sales volumes for Evangeline of 50 BBtus/d for each of the
years ended December 31, 2009, 2008 and 2007,
respectively.
|
||||||||||||
Comparison
of Results of Operations
The following table summarizes the key
components of our results of operations for the periods indicated (dollars in
millions):
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Revenues
|
$ | 979.3 | $ | 1,598.1 | $ | 1,220.3 | ||||||
|
Operating
costs and expenses
|
908.3 | 1,512.8 | 1,171.0 | |||||||||
|
General
and administrative costs
|
11.2 | 18.3 | 13.1 | |||||||||
|
Equity
in income of Evangeline
|
1.1 | 0.9 | 0.2 | |||||||||
|
Operating
income
|
60.9 | 67.9 | 36.4 | |||||||||
|
Interest
expense
|
14.0 | 12.0 | 9.3 | |||||||||
|
Net
income
|
45.8 | 55.3 | 23.6 | |||||||||
|
Net
loss (income) attributable to noncontrolling interest:
|
||||||||||||
|
DEP
I Midstream Businesses – Parent
|
(15.3 | ) | (11.4 | ) | (20.0 | ) | ||||||
|
DEP
II Midstream Businesses – Parent
|
60.6 | 4.0 | -- | |||||||||
|
Net
income attributable to Duncan Energy Partners
|
91.1 | 47.9 | 3.6 | |||||||||
For information regarding our
noncontrolling interest amounts, see Note 13 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report.
Our gross operating margin by business
segment and in total is as follows for the periods indicated (dollars in
millions):
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Natural
Gas Pipelines & Services
|
$ | 148.2 | $ | 159.0 | $ | 122.5 | ||||||
|
NGL
Pipelines & Services
|
103.4 | 82.9 | 87.9 | |||||||||
|
Petrochemical
Services
|
10.5 | 11.1 | 14.3 | |||||||||
|
Total
segment gross operating margin
|
$ | 262.1 | $ | 253.0 | $ | 224.7 | ||||||
For a reconciliation of non-GAAP gross
operating margin to GAAP operating income and further to GAAP net income, see
“Other Items – Non-GAAP Reconciliations” within this Item 7. For
additional information regarding our business segments, see Note 13 of the Notes
to Consolidated Financial Statements included under Item 8 within this annual
report.
The
following table summarizes the contribution to revenues from each business
segment (including the effects of eliminations and adjustments) during the
periods indicated (dollars in millions):
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Natural
Gas Pipelines & Services:
|
||||||||||||
|
Sales
of natural gas
|
$ | 460.2 | $ | 1,100.2 | $ | 794.1 | ||||||
|
Natural
gas transportation services
|
263.2 | 246.7 | 212.8 | |||||||||
|
Natural
gas storage services
|
15.3 | 8.4 | 1.5 | |||||||||
|
Total
segment revenues
|
$ | 738.7 | $ | 1,355.3 | $ | 1,008.4 | ||||||
|
NGL
Pipelines & Services:
|
||||||||||||
|
Sales
of NGLs
|
$ | 35.0 | $ | 47.9 | $ | 40.3 | ||||||
|
Sales
of other products
|
11.3 | 15.0 | 10.8 | |||||||||
|
NGL
and petrochemical storage services
|
104.9 | 87.4 | 68.9 | |||||||||
|
NGL
fractionation services
|
29.5 | 32.4 | 30.3 | |||||||||
|
NGL
transportation services
|
43.8 | 43.6 | 42.5 | |||||||||
|
Other
services
|
2.5 | 2.3 | 1.7 | |||||||||
|
Total
segment revenues
|
$ | 227.0 | $ | 228.6 | $ | 194.5 | ||||||
|
Petrochemical
Services:
|
||||||||||||
|
Propylene
transportation services
|
$ | 13.6 | $ | 14.2 | $ | 17.4 | ||||||
|
Total
consolidated revenues
|
$ | 979.3 | $ | 1,598.1 | $ | 1,220.3 | ||||||
Comparison
of Year Ended December 31, 2009 with Year Ended December 31, 2008
Revenues
for 2009 were $979.3 million compared to $1.60 billion for 2008. The
$618.8 million year-to-year decrease in our revenues is primarily due to lower
energy commodity sales volumes and prices during 2009 relative to
2008. These factors accounted for a $656.6 million year-to-year
decrease in revenues from the sale of natural gas and
NGLs. Revenues from natural gas transportation and
storage services increased $23.4 million year-to-year primarily due to firm
capacity reservation fees earned by our Sherman Extension pipeline during
2009. The Sherman Extension pipeline began earning capacity
reservation fees during August 2009.
Revenues
from NGL fractionation, transportation, storage and other services increased
$15.0 million year-to-year primarily due to increased NGL storage activity and
higher storage fees. Revenues from propylene transportation decreased
$0.6 million year-to-year due to lower transportation volumes in 2009 relative
to 2008.
Operating
costs and expenses were $908.3 million for 2009 versus $1.51 billion for
2008. The $604.5 million year-to-year decrease in our operating costs
and expenses is primarily due to a decrease in the cost of sales associated with
our natural gas and NGL marketing activities. The cost of sales of
our natural gas and NGL products decreased $644.2 million year-to-year as a
result of lower sales volumes and energy commodity prices. Costs and
expenses related to natural gas transportation and storage
services increased $24.1 million year-to-year. Operating costs
and expenses were lower during 2008 when we recorded favorable adjustments for
certain audit claims and changes in anticipated costs to complete an
environmental remediation project. In addition, operating expenses
increased during 2009 due to higher employee compensation and maintenance
expenses and operating expenses for the Sherman Extension
pipeline.
Costs and expenses of our NGL
fractionation, transportation, storage and other services decreased $7.6 million
year-to-year primarily due to lower operational measurement losses at Mont
Belvieu Caverns' storage complex and lower fuel and maintenance
expenses. Collectively, the remainder of our consolidated
operating
costs and expenses increased $23.2 million year-to-year as a result of higher
depreciation expense due to our recent completion of the Sherman Extension
pipeline and $4.2 million of non-cash impairment charges recorded in
2009.
Changes in our revenues and operating
costs and expenses year-to-year are explained in part by changes in energy
commodity prices. In general, lower energy commodity prices result in
a decrease in our
revenues
attributable to the sale of natural gas and NGLs; however, these lower commodity
prices also decrease the associated cost of sales as purchase prices fall.
The market price of natural gas (as measured at Henry Hub in Louisiana) averaged
$3.99 per MMBtu during 2009 versus $9.04 per MMBtu during 2008 – a 56%
year-to-year decrease. The weighted-average indicative market price
for NGLs was $0.85 per gallon during 2009 versus $1.40 per gallon during 2008 –
a 39% year-to-year decrease. Our determination of the
weighted-average indicative market price for NGLs is based on U.S. Gulf Coast
prices for such products at Mont Belvieu, Texas, which is the primary industry
hub for domestic NGL production.
General and administrative costs were
$11.2 million for 2009 compared to $18.3 million for 2008. The $7.1
million year-to-year decrease in general and administrative costs is primarily
due to lower costs associated with the DEP II Midstream
Businesses. Equity earnings from Evangeline increased $0.2 million
year-to-year.
Operating income for 2009 was $60.9
million compared to $67.9 million for 2008. Consolidated revenues and
certain operating costs and expenses can fluctuate significantly due to changes
in energy commodity prices without necessarily affecting our operating income to
the same degree. Consequently, the aforementioned changes in
revenues, costs and expenses and equity earnings contributed to the $7.0 million
year-to-year decrease in operating income.
Interest expense increased $2.0 million
year-to-year primarily due to borrowings we made in connection with the DEP II
drop down transaction in December 2008. See Note 11 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual report
for information regarding borrowings we made during December
2008. Provision for income taxes increased $0.2 million year-to-year
primarily due to the Texas Margin Tax.
As a result of items noted in the
previous paragraphs, net income decreased $9.5 million year-to-year to $45.8
million for 2009 compared to $55.3 million for 2008.
We account for EPO’s share of the net
income of the DEP I and DEP II Midstream Businesses as noncontrolling interest,
which is an adjustment to total net income to arrive at the amount of net income
attributable to Duncan Energy Partners L.P. EPO was attributed $15.3
million of the net income of the DEP I Midstream Businesses during 2009 compared
to $11.4 million during 2008. The year-to-year variance in EPO’s
share of the net income of the DEP I Midstream Businesses is primarily due to
improved earnings from these businesses. See Note 13 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual report
for information regarding our determination of net income attributable to EPO’s
noncontrolling interest.
EPO was attributed $60.6 million of
losses in connection with its ownership interests in the DEP II Midstream
Businesses during 2009 compared to $4.0 million of losses for the period from
December 8, 2008 to December 31, 2008. In the aggregate, the DEP II
Midstream Businesses distributed $116.3 million of cash and posted net losses of
$0.5 million during 2009. As a result of its priority return rights
in the DEP II Midstream Businesses, Duncan Energy Partners received its full
cash distributions of $86.5 million and was
attributed income of $60.1 million from these businesses for
2009. EPO is attributed a loss to the extent that aggregate net
income for the DEP II Midstream Businesses is less than the income attributed by
these businesses to Duncan Energy Partners. EPO received $29.8
million in cash distributions from the DEP II Midstream Businesses in
2009.
The following information highlights
significant year-to-year variances in gross operating margin by business
segment:
Natural
Gas Pipelines & Services. Gross operating margin from this
business segment was $148.2 million for 2009 compared to $159.0 million for
2008, a $10.8 million year-to-year decrease. Total natural gas
throughput volumes were 4,658 BBtus/d for 2009 compared to 4,730 BBtus/d for
2008. Gross operating margin from our natural gas pipelines includes
$24.8 million of firm capacity reservation fees earned by our Sherman Extension
pipeline during 2009. Contributions to gross operating margin from
our Sherman Extension pipeline were more than offset by a year-to-year increase
in operating expenses on our
Texas Intrastate System, lower
revenues from the sale of pipeline condensate and lower natural gas sales
volumes and margins on the Acadian Gas System.
Gross
operating margin from our Wilson natural gas storage facility increased $5.4
million year-to-year primarily due to higher firm storage reservation fees
earned during 2009 compared to 2008.
NGL
Pipelines & Services. Gross operating margin from this
business segment was $103.4 million for 2009 compared to $82.9 million for 2008,
a $20.5 million year-to-year increase. Gross operating margin from
Mont Belvieu Caverns’ storage complex increased $22.9 million
year-to-year. Mont Belvieu Caverns recorded operational measurement
losses of $1.7 million for 2009 compared to operational measurement losses of
$6.8 million for 2008. Net of operational measurement losses, gross
operating margin from Mont Belvieu Caverns’ storage complex increased $17.8
million year-to-year as a result of higher revenues due to increased
storage reservation and excess throughput fees and higher storage volumes.
Collectively, gross operating margin from the remainder of the businesses
classified within this segment decreased $2.4 million year-to-year primarily due
to lower NGL sales margins and lower NGL transportation and fractionation
volumes.
Petrochemical
Services. Gross operating margin from this business segment
was $10.5 million for 2009 compared to $11.1 million for
2008. Petrochemical transportation volumes decreased to 30 MBPD
during 2009 from 35 MBPD during 2008. The $0.6 million year-to-year
decrease in segment gross operating margin is primarily due to lower
transportation volumes on our Lou-Tex Propylene Pipeline.
Comparison
of Year Ended December 31, 2008 with Year Ended December 31, 2007
Revenues
for 2008 were $1.60 billion compared to $1.22 billion for 2007. The
$377.8 million year-to-year increase in our revenues is primarily due to higher
energy commodity sales volumes and prices during 2008 relative to
2007. These factors accounted for a $317.9 million year-to-year
increase in revenues from the sale of natural gas and
NGLs. Revenues from our natural gas transportation and storage
businesses increased $40.8 million year-to-year primarily due to higher pipeline
transportation fees and volumes during 2008 relative to
2007. Revenues from NGL fractionation, transportation, storage and
other services increased $22.3 million year-to-year primarily due to increased
NGL storage activity and higher storage fees. Revenues from propylene
transportation decreased $3.2 million year-to-year due to lower transportation
fees and volumes in 2008 relative to 2007.
Operating costs and expenses were $1.51
billion for 2008 versus $1.17 billion for 2007. The $341.8 million
year-to-year increase in our operating costs and expenses is primarily due to an
increase in the cost of sales associated with our natural gas and NGL marketing
activities. The cost of sales of our natural gas and NGL products
increased $308.1 million year-to-year as a result of an increase in volumes and
energy commodity prices. Costs and expenses from our natural gas
transportation and storage businesses increased $15.9 million year-to-year
primarily due to higher repair and maintenance expenses. Costs
and expenses from NGL fractionation, transportation, storage and other services
increased $26.1 million year-to-year primarily due to higher operating costs and
expenses from Mont Belvieu Caverns’
storage complex. Collectively, the remainder of our consolidated
operating costs and expenses decreased $8.3 million year-to-year primarily due
to lower depreciation expense for 2008 compared to 2007.
In the first quarter of 2008, we
reviewed the assumptions underlying the estimated remaining economic lives of
our assets. As a result of our review, we increased the remaining
useful lives of certain assets as of January 1, 2008, most notably the assets
that constitute our Texas Intrastate System. These revisions extended
the remaining useful life of such assets to incorporate recent data showing that
proved natural gas reserves supporting volumes for these assets had increased
their estimated useful life. There were no changes to the residual values of
these assets. These revisions prospectively reduced our depreciation
expense on assets having carrying values totaling $2.72 billion at
January 1, 2008. As a result of this change in estimate,
depreciation expense decreased by approximately $20.0 million for the year ended
December 31, 2008. The reduction in depreciation expense increased
operating income and net income by equal amounts from what they would have been
absent the change. Overall, depreciation, amortization and accretion
expense included in operating costs and expenses was $167.3 million and
$175.3
million for the years ended December 31, 2008 and 2007,
respectively. The reduction in depreciation expense in 2008 resulting
from the change in estimate was partially offset by depreciation expense on
newly constructed assets that were placed in service during 2008, primarily
additions to our Texas Intrastate System and Mont Belvieu storage
complex.
Changes
in our revenues and operating costs and expenses year-to-year are explained in
part by changes in energy commodity prices. The Henry Hub market
price of natural gas averaged $9.04 per MMBtu during 2008 versus $6.86 per MMBtu
during 2007. The weighted-average indicative market price for NGLs
was $1.40 per gallon during 2008 versus $1.19 per gallon during
2007.
General
and administrative costs were $18.3 million for 2008 compared to $13.1 million
for 2007. The $5.2 million year-to-year increase in general and administrative
costs is primarily due to higher employee-related costs and professional
services. Equity earnings from Evangeline increased $0.7 million
year-to-year.
Operating
income for 2008 was $67.9 million compared to $36.4 million for
2007. Collectively, the aforementioned changes in revenues, costs and
expenses and equity earnings contributed to the $31.5 million year-to-year
increase in operating income.
Interest
expense increased $2.7 million year-to-year primarily due to borrowings we made
in connection with the DEP II drop down transaction in December 2008 and a
decrease in the amount of interest capitalized during 2008 relative to
2007. Provision for income taxes decreased $3.1 million year-to-year
primarily due to lower accruals for the Texas Margin Tax during 2008 compared to
2007.
As a
result of items noted in the previous paragraphs, net income increased $31.7
million year-to-year to $55.3 million for 2008 compared to $23.6 million for
2007.
We
account for EPO’s share of the net income of the DEP I and DEP II Midstream
Businesses as noncontrolling interest, which is an adjustment to total net
income to arrive at the amount of net income attributable to Duncan Energy
Partners L.P. EPO was attributed $11.4 million of the net income of
the DEP I Midstream Businesses during 2008 compared to $20.0 million during
2008. The year-to-year variance in EPO’s share of the net income of
the DEP I Midstream Businesses is primarily due to the special allocations of
operational measurement gains and losses and depreciation expense to
EPO. EPO was attributed $4.0 million of losses in connection with its
ownership interests in the DEP II Midstream Businesses for the period from
December 8, 2008 to December 31, 2008.
The
following information highlights significant year-to-year variances in gross
operating margin by business segment:
Natural
Gas Pipelines & Services. Gross operating margin from this
business segment was $159.0 million for 2008 compared to $122.5 million for
2007, a $36.5 million year-to-year increase. Total natural
gas throughput volumes were 4,730 BBtus/d for 2008 compared to 4,274 BBtus/d for
2007. Gross operating margin from our Texas Intrastate System
increased $23.6 million year-to-year attributable to: (i) a 471 BBtus/d
year-to-year increase in natural gas throughput volumes; (ii) increased
transportation and capacity reservation fees; and (iii) higher NGL condensate
sales revenues. Gross operating margin from our Acadian Gas System
increased $6.4 million year-to-year largely due to improved natural gas sales
margins during 2008 relative to 2007. Collectively, results for the
Texas Intrastate and Acadian Gas Systems include $1.2 million of property damage
repair expenses during 2008 resulting from Hurricanes Gustav and
Ike. Equity earnings from our investment in Evangeline increased $0.7
million year-to-year primarily due to higher volumes, lower pipeline integrity
expenses and lower interest expense during 2008 relative to 2007.
Gross
operating margin from our Wilson natural gas storage facility increased $5.8
million year-to-year. Results from this facility were negatively
impacted during 2007 due to expenses related to mechanical issues and ongoing
repairs. Storage volumes increased during 2008 as we completed
repairs and began returning the storage caverns to commercial
service.
NGL
Pipelines & Services. Gross operating margin from this
business segment was $82.9 million for 2008 compared to $87.9 million for 2007,
a $5.0 million year-to-year decrease. Gross operating margin from
Mont Belvieu Caverns’ storage complex decreased $2.7 million
year-to-year.
Mont
Belvieu Caverns recorded operational measurement losses of $6.8 million for
2008 compared to operational measurement gains of $4.5 million for
2007. Net of operational measurement gains and losses, gross
operating margin from Mont Belvieu Caverns’ storage complex increased $8.6
million year-to-year as a result of higher revenues due to increased
storage reservation and excess throughput fees and higher storage volumes.
Collectively, gross operating margin from the remainder of the businesses
classified within this segment decreased $2.3 million year-to-year primarily due
to higher expenses for repair and maintenance and pipeline integrity on our
South Texas NGL System. Segment operating costs and expenses for 2008
include $0.4 million of property damage repair expenses resulting from Hurricane
Ike.
Petrochemical
Services. Gross
operating margin from this business segment was $11.1 million for 2008
compared to $14.3 million for 2007. Petrochemical transportation
volumes decreased to 35 MBPD during 2008 from 37 MBPD during
2007. The $3.2 million year-to-year decrease in segment gross
operating margin is primarily due to lower transportation volumes and fees on
our Lou-Tex Propylene Pipeline.
Liquidity
and Capital Resources
Our
primary cash requirements, in addition to normal operating expenses and debt
service, are for working capital, capital expenditures, business combinations
and distributions to our partners. We expect to fund our short-term
needs for such items as operating expenses and sustaining capital expenditures
with operating cash flows and borrowings under our Revolving Credit
Facility. Capital expenditures for long-term needs resulting from
business expansion projects and acquisitions are expected to be funded by a
variety of sources (either separately or in combination) including operating
cash flows, borrowings under credit facilities, cash contributions from our
Parent, the issuance of additional equity and debt securities and proceeds from
divestitures of ownership interests in assets to affiliates or third
parties. We expect to fund cash distributions to partners primarily
with operating cash flows. Our debt service requirements are expected
to be funded by operating cash flows and/or refinancing
arrangements.
At December 31, 2009, we had
approximately $121 million of liquidity, which includes availability under our
Revolving Credit Facility. At December 31, 2009, our total debt
balance was $457.3 million, which includes $175.0 million outstanding under our
Revolving Credit Facility and the $282.3 million we borrowed on December 8, 2008
under our Term Loan Agreement. We were in compliance with the
covenants of our loan agreements at December 31, 2009 and 2008.
It is our
belief that we will continue to have adequate liquidity and capital resources to
fund future recurring operating and investing activities for the next twelve
months. For a discussion of our liquidity outlook, see “General
Outlook for 2010” within this Item 7.
Registration
Statements
We may issue equity or debt securities
to assist us in meeting our liquidity and capital spending
requirements. We have a universal shelf registration statement on
file with the SEC that allows us to issue up to $1 billion in debt and equity
securities for general partnership purposes. After taking into
account a June 2009 equity offering made under this registration statement (see
table below), we can issue approximately $856.4 million of additional securities
under this registration statement in the future.
|
Underwritten
Equity Offering
|
Number
of Common Units Issued
|
Offering
Price
(1)
|
Net
Proceeds
(2)
(in
millions)
|
|||||||||
|
June
2009 underwritten offering (3)
|
8,943,400 | $ | 16.00 | $ | 137.4 | |||||||
|
(1)
The
public offering price, net of the underwriting discount, was $15.36 per
unit.
(2)
Net
proceeds from these equity offerings were used to repurchase an equal
number of our common units beneficially owned by EPO.
(3)
Includes
our underwriters’ exercise of a portion of their 30-day option to purchase
additional common units.
|
||||||||||||
We also have a registration statement
on file with the SEC authorizing the issuance of up to 2,000,000 common units in
connection with the DRIP. The DRIP gives unitholders of record and
beneficial owners of our common units the ability to increase the number of our
common units they own through voluntarily reinvesting their quarterly cash
distributions into the purchase of additional common units. Plan
participants may purchase our common units at a discount ranging from 0% to 5%
(currently set at 5%), which will be set from time to time by us. We did not
issue any common units under the DRIP during the year ended December 31,
2009. In February 2010, we issued 10,385 common units in connection
with the DRIP.
In
February 2010, we filed a registration statement with the SEC authorizing the
issuance of up to 1,000,000 common units in connection with an employee unit
purchase plan and a long-term incentive plan. These plans became
effective on February 11, 2010. See Item 9B for additional
information.
Cash
Flows from Operating, Investing and Financing Activities
The
following table summarizes our cash flows from operating, investing and
financing activities for the periods indicated (dollars in
millions). For information regarding the individual components of our
cash flow amounts, see the Statements of Consolidated Cash Flows included under
Item 8 within this annual report.
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
cash flows provided by operating activities
|
$ | 156.0 | $ | 220.1 | $ | 217.1 | ||||||
|
Cash
used in investing activities
|
383.2 | 748.8 | 352.4 | |||||||||
|
Cash
provided by financing activities
|
218.1 | 539.5 | 137.5 | |||||||||
We use the indirect method to compute
net cash flows provided by operating activities. Net cash flows
provided by operating activities are largely dependent on earnings from our
business activities. As a result, these cash flows are exposed to
certain risks. We operate predominantly in the midstream energy
industry. We provide services for producers and consumers of natural
gas, NGLs and certain petrochemicals. The products that we
fractionate, sell or transport are principally used as fuel for residential,
agricultural and commercial heating; as feedstocks in petrochemical
manufacturing; and in the production of motor gasoline. Reduced
demand for our services or products by industrial customers, whether because of
a decline in general economic conditions, reduced demand for the end products
made
with our
products, or increased competition from other service providers or producers due
to pricing differences or other reasons, could have a negative impact on our
earnings and operating cash flows.
Cash used
in investing activities primarily represents expenditures for additions to
property, plant and equipment. Cash provided by financing activities
generally consists of borrowings and repayments of debt, distributions to and
contributions from owners, and proceeds from the issuance of equity
securities.
The
following information highlights the significant year-to-year variances in our
cash flow amounts:
Comparison
of 2009 with 2008
Operating
activities. Net cash flows provided by operating activities
were $156.0 million for the year ended December 31, 2009 compared to $220.1
million for the year ended December 31, 2008. The change in operating
cash flow is primarily due to the timing of related cash receipts and
disbursements offset by a $9.1 million increase in gross operating margin for
the year ended December 31, 2009 in comparison to the year ended December 31,
2008.
Investing
activities. Cash flows used in investing activities were
$383.2 million for the year ended December 31, 2009 compared to $748.8 million
for the year ended December 31, 2008. The $365.6 million year-to-year
decrease is primarily due to the completion of growth capital projects on the
DEP II Midstream Businesses that were under construction in 2008. In
February 2009, we completed the construction of the Sherman Extension Pipeline,
which is a component of our Texas Intrastate System. The Sherman
Extension Pipeline began operations on August 1, 2009.
Financing
activities. Cash flows provided by financing activities were $218.1
million for the year ended December 31, 2009 compared to $539.5 million for the
year ended December 31, 2008. The $321.4 million year-to-year
decrease is due to: (i) a $222.9 million decrease in net contributions,
primarily related to growth capital projects, from EPO as both a former owner
(pre-drop down) and as noncontrolling interest; (ii) a $311.2 million decrease
in net borrowings under our loan agreements; (iii) a $54.5 million increase in
distributions to our unitholders and general partners; (iv) a $14.0 million
increase in distributions to EPO; and (v) a $280.5 decrease in distributions to
EPO related to the DEP II drop down in 2008.
Comparison
of 2008 with 2007
Operating
activities. Net cash flows provided by operating activities
were $220.1 million for the year ended December 31, 2008 compared to $217.1
million for the year ended December 31, 2007. The improvement in
operating cash flow is generally due to the increase in gross operating margin
between periods (see “Results of Operations” included within this Item 7)
adjusted for the timing of related cash receipts and disbursements.
Investing
activities. Net cash flows used in investing activities were
$748.8 million for the year ended December 31, 2008 compared to $352.4 million
for the year ended December 31, 2007. The increase of $396.4 million
is primarily due to growth capital spending for additions to property, plant and
equipment of the DEP II Midstream Businesses (e.g., the Sherman Extension
Pipeline).
Financing
activities. Net cash flows provided by financing activities
were $539.5 million for the year ended December 31, 2008 compared to $137.5
million for the year ended December 31, 2007. The increase of $402.0
million is primarily due to: (i) a $378.8 million year-to-year
increase in contributions by the former owners of the DEP II Midstream
Businesses primarily due to the funding of growth capital spending of these
businesses; (ii) a $78.3 million year-to-year increase in contributions from
EPO primarily due to growth capital spending of the DEP I Midstream
Businesses; (iii) a year-to-year increase of $84.2 million in net borrowings
under loan agreements, which consisted primarily of $282.3 received from the
execution of our Term Loan Agreement; (iv) a $290.0 million year-to-year
decrease in net
proceeds
from equity offerings; and (v) a $179.0 million year-to-year decrease in
distributions to EPO related to the DEP I and DEP II drop down
transactions.
Capital
Expenditures
Part of
our business strategy involves expansion through business combinations and
growth capital projects.The
following table summarizes our capital spending by activity on a cash basis for
the periods indicated (dollars in millions):
|
For
the Twelve Months
|
||||||||
|
Ended
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
DEP
I Midstream Businesses:
|
||||||||
|
Expansion
capital spending (1)
|
$ | 28.5 | $ | 127.7 | ||||
|
Sustaining
capital expenditures (2)
|
13.9 | 12.8 | ||||||
|
DEP
II Midstream Businesses:
|
||||||||
|
Expansion
capital spending (1)
|
311.0 | 576.5 | ||||||
|
Sustaining
capital expenditures (2)
|
35.7 | 42.5 | ||||||
|
Total
capital spending
|
$ | 389.1 | $ | 759.5 | ||||
|
(1)
EPO
funded 100% of expansion capital spending during the periods
presented.
(2)
Sustaining
capital expenditures are capital expenditures (as defined by U.S. GAAP)
resulting from improvements to and major renewals of existing
assets. Such expenditures serve to maintain existing operations but
do not generate additional revenues.
|
||||||||
The majority of our capital spending
during 2009 and 2008 was attributable to ongoing expansions of the Texas
Intrastate System, including the Sherman Extension and Trinity River Lateral
projects.
Based on
information currently available, we estimate our consolidated capital spending
for property, plant and equipment for 2010 will approximate $840 million, which
includes estimated expenditures of approximately $780 million for growth capital
projects and approximately $60 million for sustaining capital
expenditures.
Our
forecast of capital expenditures is based on current announced growth
plans. With respect to growth capital spending, EPO (as Parent) funds
the majority of such project costs under agreements executed in connection with
the DEP I and DEP II drop down transactions. In order to fund its
share of growth capital spending, Duncan Energy Partners depends on its ability
to generate the required funds from either operating cash flows or from other
means, including borrowings under debt agreements and the issuance of
equity. See Note 13 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report for information regarding EPO’s
funding of certain growth capital spending of South Texas NGL and Mont Belvieu
Caverns. For information regarding the expansion capital funding
arrangements of the DEP II Midstream Businesses, see “Significant Relationships
and Agreements with EPO - Company and Limited Partnership Agreements - DEP II
Midstream Businesses” under Note 15 of the Notes to Consolidated Financial
Statements included under Item 8 within this annual report.
At
December 31, 2009, we had approximately $175.3 million in purchase commitments
outstanding that relate to our capital spending for property, plant and
equipment. These commitments primarily relate to expansion projects
on our Texas Intrastate System and Acadian Gas System.
Pipeline
Integrity Costs
Our NGL, petrochemical and natural gas
pipelines are subject to pipeline safety programs administered by the
DOT. This federal agency has issued safety regulations containing
requirements for the development of integrity management programs for hazardous
liquid pipelines (which include NGL and petrochemical pipelines) and natural gas
pipelines. In general, these regulations require companies to assess
the condition of their pipelines in certain high consequence areas (as defined
by the regulation) and to perform any necessary repairs.
In April
2002, a subsidiary of EPO acquired several midstream energy assets, which
included the Texas Intrastate System from El Paso Corporation (“El
Paso”). With respect to these assets, El Paso agreed to indemnify our
subsidiary for any pipeline integrity costs it incurred (whether paid or
payable) for five years following the acquisition date. The indemnity
provisions did not take effect until such costs exceeded $3.3 million annually;
however, the amount reimbursable by El Paso was capped at $50.2 million in the
aggregate. In 2007, the DEP II Midstream Businesses recovered $31.1
million from El Paso related to the 2006 pipeline integrity
expenditures. During 2007, the DEP II Midstream Businesses also
received the final payment of $5.4 million from El Paso related to this
indemnity.
The
following table summarizes our pipeline integrity costs, net of indemnity
payments received from El Paso, for the periods indicated (dollars in
millions):
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Expensed
|
$ | 14.1 | $ | 20.6 | $ | 14.9 | ||||||
|
Capitalized
|
17.0 | 22.9 | 24.1 | |||||||||
|
Total
|
$ | 31.1 | $ | 43.5 | $ | 39.0 | ||||||
We expect
our cash outlay for the pipeline integrity program, irrespective of whether such
costs are capitalized or expensed, to approximate $42.5 million for
2010.
Critical
Accounting Policies and Estimates
In our
financial reporting process, we employ methods, estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities as of the date of our financial
statements. These methods, estimates and assumptions also affect the
reported amounts of revenues and expenses during the reporting
period. Investors should be aware that actual results could differ
from these estimates if the underlying assumptions prove to be
incorrect. The following describes the estimation risk currently
underlying our most significant financial statement items.
Depreciation
Methods and Estimated Useful Lives of Property, Plant and Equipment
In
general, depreciation is the systematic and rational allocation of an asset’s
cost, less its residual value (if any), to the periods it
benefits. The majority of our property, plant and equipment is
depreciated using the straight-line method, which results in depreciation
expense being incurred evenly over the life of the assets. Our
estimate of depreciation incorporates assumptions regarding the useful economic
lives and residual values of our assets. At the time we place our
assets into service, we believe such assumptions are reasonable; however,
circumstances may develop that would cause us to change these assumptions, which
would change our depreciation amounts prospectively. Examples of such
circumstances include:
|
§
|
changes
in laws and regulations that limit the estimated economic life of an
asset;
|
|
§
|
changes
in technology that render an asset
obsolete;
|
|
§
|
changes
in expected salvage values; or
|
|
§
|
changes
in the forecast life of applicable resource basins, if
any.
|
At December 31, 2009 and 2008, the net
book value of our property, plant and equipment was $4.55 billion and $4.33
billion, respectively. We recorded $176.7 million, $158.5 million and
$163.4 million in depreciation expense for the years ended December 31, 2009,
2008 and 2007, respectively.
For additional information regarding
our property, plant and equipment, including changes made in the first quarter
of 2008 in the estimated remaining useful lives of certain of our assets, see
Notes 2 and 8 of the Notes to Consolidated Financial Statements included under
Item 8 of this annual report.
Measuring
Recoverability of Long-Lived Assets and Equity Method Investments
In
general, long-lived assets (including intangible assets with finite useful lives
and property, plant and equipment) are reviewed for impairment whenever events
or changes in circumstances indicate that their carrying amount may not be
recoverable. Examples of such events or changes might be production
declines that are not replaced by new discoveries or long-term decreases in the
demand or price of natural gas, crude oil or NGLs. Long-lived assets
with recorded values that are not expected to be recovered through forecast
future cash flows are written-down to their estimated fair
values. The carrying value of a long-lived asset is not recoverable
if it exceeds the sum of undiscounted estimated cash flows expected to result
from the use and eventual disposition of the asset. Our estimates of
such undiscounted cash flows are based on a number of assumptions including
anticipated operating margins and volumes; estimated useful life of the asset or
asset group; and estimated salvage values. An impairment charge would
be recorded for the excess of a long-lived asset’s carrying value over its
estimated fair value, which is based on a series of assumptions similar to those
used to derive undiscounted cash flows. Those assumptions also
include usage of probabilities for a range of possible outcomes, market values
and replacement cost estimates.
An equity
method investment is evaluated for impairment whenever events or changes in
circumstances indicate that there is a possible loss in value of the investment
other than a temporary decline. Examples of such events include
sustained operating losses of the investee or long-term negative changes in the
investee’s industry. The carrying value of an equity method
investment is not recoverable if it exceeds the sum of the discounted estimated
cash flows expected to be derived from the investment. This estimate
of discounted cash flows is based on a number of assumptions including discount
rates; probabilities assigned to different cash flow scenarios; anticipated
margins and volumes and estimated useful life of the investment. A
significant change in these underlying assumptions could result in our recording
an impairment charge.
During
2009, we recognized $4.2 million of asset impairment charges, which are
reflected as a component of operating costs and expenses. No such
asset impairment charges were recorded in 2008 or 2007. We did not
recognize any impairment charges related to our equity method investment in
Evangeline during the three years ended December 31, 2009.
For
additional information regarding impairment charges associated with our
long-lived assets, see Note 6 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report.
Amortization
Methods and Estimated Useful Lives of Qualifying Intangible Assets
The
specific, identifiable intangible assets of a business enterprise depend largely
upon the nature of its operations. Potential intangible assets
include, intellectual property, such as technology, patents, trademarks, trade
names, customer contracts and relationships and non-compete agreements, as well
as other intangible assets. The method used to value each intangible
asset will vary depending upon a number of factors, including the nature of the
asset and the economic returns it is generating or is expected to
generate.
Our customer relationship intangible
assets primarily represent the customer bases we acquired in connection with the
DEP II drop down. These customer relationships were acquired by
Enterprise Products Partners in connection with a merger transaction it
completed in 2004 and a business combination it completed in 2007. We
amortize the value of our customer relationships to earnings using methods that
closely resemble the pattern in which the economic benefits of the underlying
NGL and natural gas resource bases from which the customers produce are
estimated to be consumed or otherwise used. Our estimate of the
useful life of each resource base is predicated on a number of factors,
including reserve estimates and the economic viability of production and
exploration activities.
We acquired contract-based intangible
assets in connection with the DEP I and DEP II drop down
transactions. Our contract-based intangible assets represent the
rights we own arising from discrete contractual agreements. A
contract-based intangible asset with a finite life is amortized over its
estimated
useful
life (or term), which is the period over which the asset is expected to
contribute directly or indirectly to the cash flows of an entity. Our
estimates of useful life are based on a number of factors,
including:
|
§
|
the
expected useful life of the related tangible assets (e.g., fractionation
facility, pipeline or other asset);
|
|
§
|
any
legal or regulatory developments that would impact such contractual
rights; and
|
|
§
|
any
contractual provisions that enable us to renew or extend such
agreements.
|
If our
underlying assumptions regarding the estimated useful life of an intangible
asset change, then the amortization period for such asset would be adjusted
accordingly. Changes in the estimated useful life of an intangible
asset would impact operating costs and expenses prospectively from the date of
change. If we determine that an intangible asset’s unamortized cost is not
recoverable due to impairment; we would be required to reduce the asset’s
carrying value to fair value. Any such write-down of the value of an
intangible asset would increase operating costs and expenses at that
time.
At
December 31, 2009 and 2008, the carrying value of our intangible asset portfolio
was $43.8 million and $52.3 million, respectively. We recorded $8.5
million, $9.1 million and $7.2 million in amortization expense associated with
our intangible assets for the years ended December 31, 2009, 2008 and 2007,
respectively.
For
additional information regarding our intangible assets, see Notes 2 and 10 of
the Notes to Consolidated Financial Statements included under Item 8 within this
annual report.
Methods
We Employ to Measure the Fair Value of Goodwill
Goodwill represents the excess of the
purchase prices we paid for certain businesses over their respective fair
values. We do not amortize goodwill; however, we test our goodwill
for impairment at the beginning of each fiscal year, and more frequently, if
circumstances indicate it is more likely than not that the fair value of
goodwill is below its carrying amount. Our goodwill testing involves
the determination of a reporting unit’s fair value, which is predicated on our
assumptions regarding the future economic prospects of the reporting
unit.
Such assumptions include:
|
§
|
discrete
financial forecasts for the assets classified within the reporting unit,
which rely on management’s estimates of operating margins and
transportation volumes;
|
|
§
|
long-term
growth rates for cash flows beyond the discrete forecast period;
and
|
|
§
|
appropriate
discount rates.
|
If the fair value of the reporting unit
(including its inherent goodwill) is less than its carrying value, a charge to
earnings is required to reduce the carrying value of the goodwill to its implied
fair value. The carrying value of our goodwill was $4.9 million at
both December 31, 2009 and 2008. Our goodwill represents an
allocation to the DEP II Midstream Businesses of the goodwill recorded by
Enterprise Products Partners in connection with a merger transaction it
completed in 2004. We did not record any goodwill impairment charges
during the three years ended December 31, 2009.
For additional information regarding
our goodwill, see Notes 2 and 10 of the Notes to Consolidated Financial
Statements included under Item 8 within this annual report.
Our
Revenue Recognition Policies and Use of Estimates for Revenues and
Expenses
In general, we recognize revenue from
customers when all of the following criteria are met:
|
§
|
persuasive
evidence of an exchange arrangement
exists;
|
|
§
|
delivery
has occurred or services have been
rendered;
|
|
§
|
the
buyer’s price is fixed or determinable;
and
|
|
§
|
collectability
is reasonably assured.
|
We record revenue when sales contracts
are settled (i.e., either physical delivery of product has taken place or the
services designated in the contract have been performed). For
additional information regarding our revenue recognition policies, see Note 4 of
the Notes to Consolidated Financial Statements included under Item 8 of this
annual report. We record any necessary allowance for doubtful
accounts as required by our established policy.
Our use
of estimates for certain revenues and expenses has increased as a result of SEC
regulations that require us to submit financial information on accelerated time
frames. Such estimates are necessary due to the time required to
compile actual billing information and receive third-party data needed to record
transactions for financial reporting purposes. Changes in facts and
circumstances may result in revised estimates and could affect our reported
financial statements and accompanying disclosures. If the assumptions underlying
our estimates prove to be substantially incorrect, it could result in material
adjustments in results of operations between periods. We review our
estimates based on currently available information.
Reserves
for Environmental Matters
Our
business activities are subject to various federal, state and local laws and
regulations governing environmental quality and pollution control. Such laws and
regulations may, in certain instances, require us to remediate current or former
operating sites where specified substances have been released or disposed of. We
accrue reserves for environmental matters when our assessments indicate that it
is probable that a liability has been incurred and an amount can be reasonably
estimated. Our assessments are based on studies, as well as site
surveys, to determine the extent of any environmental damage and the necessary
requirements to remediate this damage. Future environmental developments, such
as increasingly strict environmental laws and additional claims for damages to
property, employees and other persons resulting from current or past operations,
could result in substantial additional costs beyond our current reserves. In
accruing for environmental remediation liabilities, costs of future expenditures
for environmental remediation are not discounted to their present value, unless
the amount and timing of the expenditures are fixed or reliably
determinable. At December 31, 2009, none of our estimated environmental
remediation liabilities were discounted to present value since the ultimate
amount and timing of cash payments for such liabilities were not readily
determinable.
At December 31, 2009 and 2008, we had a
liability for environmental remediation of $0.5 million and $0.6 million,
respectively, which was derived from a range of reasonable estimates based upon
studies and site surveys. We have recorded our best estimate of the
cost of remediation activities. See Notes 2 and 17 of the Notes to
Consolidated Financial Statements included under Item 8 within this annual
report for additional information regarding environmental matters.
Natural
Gas Imbalances
In the natural gas pipeline
transportation business, imbalances frequently result from differences in
natural gas volumes received from and delivered to our customers. Such
differences occur when a customer delivers more or less gas into our pipelines
than is physically redelivered back to them during a particular time
period. The vast majority of our settlements are through in-kind
arrangements whereby incremental
volumes
are delivered to a customer (in the case of an imbalance payable) or received
from a customer (in the case of an imbalance receivable). Such in-kind
deliveries are ongoing and take place over several months. In some
cases, settlements of imbalances accumulated over a period of time are
ultimately cashed out and are generally negotiated at values which approximate
average market prices over a period of time. As a result, for gas
imbalances that are ultimately settled over future periods, we estimate the
value of such current assets and liabilities using average market prices, which
we believe is representative of the value of the imbalances upon final
settlement. Changes in natural gas prices may impact our estimates.
The
following table presents our natural gas imbalance receivables/payables at the
dates indicated:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Natural
gas imbalance receivables
|
$ | 9.8 | $ | 35.7 | ||||
|
Natural
gas imbalance payables (1)
|
11.0 | 43.6 | ||||||
|
(1)
Reflected
as a component of “Accrued product payables” on our Consolidated Balance
Sheets included in Item 8 of this annual report.
|
||||||||
Other
Items
Insurance
Matters
We participate as a named insured in
EPCO’s insurance program, which provides us with property damage, business
interruption and other coverages, the scope and amounts of which are customary
and sufficient for the nature and extent of our operations. In light
of recent hurricane and other weather-related events, the renewal of policies
for weather-related risks resulted in significant increases in premiums and
certain deductibles, as well as changes in the scope of coverage. For
additional information regarding insurance matters, see Note 18 of the Notes
Consolidated Financial Statements included under Item 8 of this annual
report.
Contractual
Obligations
The following table summarizes our
significant contractual obligations at December 31, 2009 (dollars in
millions). For additional information regarding these obligations,
see Note 17 of the Notes to Consolidated Financial Statements included under
Item 8 within this annual report.
|
Payment
or Settlement due by Period
|
||||||||||||||||||||
|
Less
than
|
1-3 | 4-5 |
More
than
|
|||||||||||||||||
|
Contractual Obligations
(1)
|
Total
|
1
year
|
years
|
years
|
5
years
|
|||||||||||||||
|
Scheduled
maturities of long term debt (2)
|
$ | 457.3 | $ | -- | $ | 457.3 | $ | -- | $ | -- | ||||||||||
|
Estimated
cash interest payments (3)
|
$ | 14.8 | $ | 11.1 | $ | 3.7 | $ | -- | $ | -- | ||||||||||
|
Operating
lease obligations (4)
|
$ | 115.6 | $ | 9.0 | $ | 17.6 | $ | 14.0 | $ | 75.0 | ||||||||||
|
Purchase
obligations:
|
||||||||||||||||||||
|
Product
purchase commitments:
|
||||||||||||||||||||
|
Estimated
payment obligations:
|
||||||||||||||||||||
|
Natural
gas (5)
|
$ | 511.7 | $ | 257.3 | $ | 254.4 | $ | -- | $ | -- | ||||||||||
|
Other
|
$ | 0.1 | $ | * | $ | 0.1 | $ | -- | $ | -- | ||||||||||
|
Underlying
major volume commitments:
|
||||||||||||||||||||
|
Natural
gas (in BBtus)
|
77,207 | 40,657 | 36,550 | -- | -- | |||||||||||||||
|
Capital
expenditure commitments (6)
|
$ | 175.3 | $ | 175.3 | $ | -- | $ | -- | $ | -- | ||||||||||
|
Other
long-term liabilities (7)
|
$ | 6.4 | $ | -- | $ | 0.2 | $ | -- | $ | 6.2 | ||||||||||
|
Total
|
$ | 1,281.2 | $ | 452.7 | $ | 733.3 | $ | 14.0 | $ | 81.2 | ||||||||||
|
*
Indicates amounts are immaterial and less than $0.1
million.
|
||||||||||||||||||||
|
(1)
The
contractual obligations presented in this table reflect 100% of our
subsidiaries’ obligations even though we own less than a 100% equity
interest in our operating subsidiaries.
(2)
Represents
our scheduled future maturities of consolidated debt principal obligations
for the periods indicated. See Note 11 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report for
information regarding our debt obligations.
(3)
Our
estimated cash payments for interest are based on the principle amount of
consolidated debt obligations outstanding at December 31, 2009. In
calculating these amounts, we applied the weighted-average variable
interest rates paid during 2009 associated with such debt. See Note
11 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report for the weighted-average variable interest rates
charged in 2009 under our credit agreements. In addition, our
estimate of cash payments for interest gives effect to interest rate swap
agreements that were in place at December 31, 2009. See Note 6 of the
Notes to Consolidated Financial Statements included under Item 8 of this
annual report for information regarding these derivative
instruments.
(4)
Primarily
represents operating leases for (i) underground caverns for the storage of
natural gas and NGLs and (ii) land held pursuant to right-of-way
agreements. See Note 17 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for information
regarding our operating leases.
(5)
Represents
natural gas purchase commitments of Acadian Gas to satisfy its sales
commitments to Evangeline. See Note 17 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report for
information regarding our purchase obligations. The estimated payment
obligations are based on contractual prices in effect at December 31, 2009
applied to all future volume commitments. Actual future payment
obligations may vary depending on prices at the time of
delivery.
(6)
Represents
short-term unconditional payment obligations related to our capital
projects (on a 100% basis). With respect to the amount presented, we
expect reimbursements of $113.9 million from EPO.
(7)
As
reflected on our Consolidated Balance Sheet at December 31, 2009, other
long-term liabilities primarily represent noncurrent portions of
asset retirement obligations. For information regarding our
asset retirement obligations, see Note 7 of our Notes to Consolidated
Financial Statements included under Item 8 of this annual
report.
|
||||||||||||||||||||
Off-Balance
Sheet Arrangements
At December 31, 2009, Evangeline’s debt
obligations consisted of (i) $3.2 million in principal amount of 9.90% fixed
rate Series B senior secured notes due December 2010 and (ii) a $7.5 million
subordinated note payable, due in 2011. Evangeline expects to fund
the repayment of its debt obligations (including accrued interest) using
operating cash flows.
We have
no other off-balance sheet arrangements, as described in Item 303(a)(4)(ii) of
Regulation S-K, that have had or are reasonably expected to have a material
current or future effect on our financial position, revenues or expenses,
results of operations, liquidity, capital expenditures or capital
resources.
Related
Party Transactions
For information regarding our related
party transactions, see Note 15 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report as well as Item 13 of
this annual report.
Non-GAAP
Reconciliations
The following table presents a
reconciliation of our non-GAAP measure of total segment gross operating margin
to GAAP operating income and net income for the periods indicated (dollars in
millions):
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Total
segment gross operating margin
|
$ | 262.1 | $ | 253.0 | $ | 224.7 | ||||||
|
Adjustments
to reconcile total segment gross operating margin
|
||||||||||||
|
to
operating income:
|
||||||||||||
|
Depreciation,
amortization and accretion in
|
||||||||||||
|
operating
costs and expenses
|
(186.3 | ) | (167.3 | ) | (175.3 | ) | ||||||
|
Impairment
charge included in operating
|
||||||||||||
|
costs
and expenses
|
(4.2 | ) | -- | -- | ||||||||
|
Gain
on asset sales and related transactions in
|
||||||||||||
|
operating
costs and expenses
|
0.5 | 0.5 | 0.1 | |||||||||
|
General
and administrative costs
|
(11.2 | ) | (18.3 | ) | (13.1 | ) | ||||||
|
GAAP operating
income
|
60.9 | 67.9 | 36.4 | |||||||||
|
Other
income (expense), net
|
(13.8 | ) | (11.5 | ) | (8.6 | ) | ||||||
|
Provision
for income taxes
|
(1.3 | ) | (1.1 | ) | (4.2 | ) | ||||||
|
GAAP
net income
|
$ | 45.8 | $ | 55.3 | $ | 23.6 | ||||||
Recent
Accounting Developments
The accounting standard setting bodies
have recently issued accounting guidance that will or may affect our future
financial statements:
|
§
|
Fair
Value Measurements; and
|
|
§
|
Consolidation
of Variable Interest Entities
|
For additional information regarding
these recent accounting developments, see Note 3 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report.
In the
course of our normal business operations, we are exposed to certain risks,
including changes in interest rates and commodity prices. In order to
manage risks associated with certain identifiable and anticipated transactions,
we use derivative instruments. Derivatives are instruments whose fair
value is determined by changes in a specified benchmark such as interest rates,
commodity prices or currency values. Typical derivative instruments
include futures, forward contracts, swaps, options and other instruments with
similar characteristics. Substantially all of our derivatives are
used for non-trading activities.
See Note
6 of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report for additional information regarding our derivative
instruments outstanding and related hedging activities, including associated
fair value measurements. See Note 12 of the Notes to Consolidated
Financial Statements for information regarding the impact of derivative
instruments on accumulated other comprehensive loss as reported on our
Consolidated Balance Sheets.
Interest
Rate Derivative Instruments
We
utilize interest rate swaps to manage our exposure to changes in the interest
rates of certain consolidated debt agreements. This strategy is a
component in controlling our cost of capital associated with such
borrowings.
The following table shows the effect of
hypothetical price movements (a sensitivity analysis) on the estimated fair
value (“FV”) of our interest rate swap portfolio (dollars in
millions).
|
Portfolio
FV at
|
|||||||||||||
|
Scenario
|
Resulting
Classification
|
December
31, 2008
|
December
31, 2009
|
January
31, 2010
|
|||||||||
|
FV
assuming no change in underlying interest rates
|
Liability
|
$ | 9.8 | $ | 5.5 | $ | 5.7 | ||||||
|
FV
assuming 10% increase in underlying interest rates
|
Liability
|
9.4 | 5.5 | 5.7 | |||||||||
|
FV
assuming 10% decrease in underlying interest rates
|
Liability
|
10.2 | 5.6 | 5.7 | |||||||||
Commodity
Derivative Instruments
The price
of natural gas fluctuates in response to changes in supply and demand, market
conditions, and a variety of additional factors that are beyond our
control. We may use commodity-based derivative instruments such as
futures, swaps and forward contracts to mitigate such risks.
We assess
the risk of our commodity financial instrument portfolios using a sensitivity
analysis model. The sensitivity analysis applied to these portfolios
measures the potential income or loss (i.e., the change in fair value of the
portfolio) based upon a hypothetical 10% movement in the underlying quoted
market prices of the commodity derivative instruments outstanding at the date
indicated within the following tables.
The
following table presents the effect of hypothetical price movements on the
estimated fair value of this portfolio at the dates presented (dollars in
millions).
|
Portfolio
FV at
|
|||||||||||||
|
Scenario
|
Resulting
Classification
|
December
31, 2008
|
December
31, 2009
|
January
31, 2010
|
|||||||||
|
FV
assuming no change in underlying commodity prices
|
Asset
(Liability)
|
$ | (0.1 | ) | $ | * | $ | * | |||||
|
FV
assuming 10% increase in underlying commodity prices
|
Asset
(Liability)
|
(0.1 | ) | * | * | ||||||||
|
FV
assuming 10% decrease in underlying commodity prices
|
Asset
(Liability)
|
(0.1 | ) | * | * | ||||||||
|
* Indicates
that amounts are negligible and less than $0.1 million
|
|||||||||||||
Product
Purchase Commitments
We have
long and short-term purchase commitments for natural gas. The
purchase prices that we are obligated to pay under these contracts are based on
market prices at the time we take delivery of the volumes. For
additional information regarding these commitments, see “Contractual
Obligations” included under Item 7 of this annual report.
Our consolidated financial statements,
together with the independent registered public accounting firm’s report of
Deloitte & Touche LLP (“Deloitte & Touche”) begin on page F-1 of this
annual report.
None.
As of the end of the period covered by
this annual report, our management carried out an evaluation, with the
participation of our general partner’s chief executive officer (our principal
executive officer) (the “CEO”) and our general partner’s chief financial officer
(our principal financial officer) (the “CFO”), of the effectiveness of our
disclosure controls and procedures pursuant to Rule 13a-15 of the Securities
Exchange Act of 1934. Based on that evaluation, as of the end of the
period covered by this annual report, the CEO and CFO concluded:
|
(i)
|
that
our disclosure controls and procedures are designed to ensure that
information required to be disclosed by us in the reports that we file or
submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and communicated
to our management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure;
and
|
|
(ii)
|
that
our disclosure controls and procedures are
effective.
|
Changes
in Internal Control over Financial Reporting
There were no changes in our internal
controls over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934) or in other factors during the fourth quarter
of 2009, that have materially affected, or are reasonably likely to materially
affect, our internal controls over financial reporting.
The certifications of our general
partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley
Act of 2002 have been included as exhibits to this annual report.
MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL
OVER
FINANCIAL REPORTING AS OF DECEMBER 31, 2009
The management of Duncan Energy
Partners L.P. and its consolidated subsidiaries, including its chief executive
officer and chief financial officer, is responsible for establishing and
maintaining adequate internal control over financial reporting, as defined in
Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as
amended. Our internal control system was designed to provide
reasonable assurance to Duncan Energy Partners’ management and Board of
Directors regarding the preparation and fair presentation of published financial
statements. However, our management does not represent that our
disclosure controls and procedures or internal controls over financial reporting
will prevent all error and all fraud. A control system, no matter how
well conceived and operated, can provide only a reasonable, not an absolute,
assurance that the objectives of the control system are met.
Our management assessed the
effectiveness of Duncan Energy Partners’ internal control over financial
reporting as of December 31, 2009. In making this assessment, it used
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”) in Internal Control—Integrated
Framework. This assessment included a review of the design and
operating effectiveness of internal controls over financial reporting as well as
the safeguarding of assets. Based on our assessment, we believe that, as of
December 31, 2009, Duncan Energy Partners’ internal control over financial
reporting is effective based on those criteria.
Our Audit, Conflicts and Governance
Committee is composed of directors who are not officers or employees of our
general partner. It meets regularly with members of management, the
internal auditors and the representatives of the independent registered public
accounting firm to discuss the adequacy of Duncan Energy Partners’ internal
controls over financial reporting, financial statements and the nature, extent
and results of the audit effort. Management reviews with the Audit,
Conflicts and Governance Committee all of Duncan Energy Partners’ significant
accounting policies and assumptions affecting the results of
operations. Both the independent registered public accounting firm
and internal auditors have direct access to the Audit, Conflicts and Governance
Committee without the presence of management.
Our independent registered public
accounting firm has issued an attestation report on our internal control over
financial reporting. That report is included within this Item
9A.
Pursuant to the requirements of Rules
13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this
Annual Report on Internal Control over Financial Reporting has been signed below
by the following persons on behalf of the registrant and in the capacities
indicated below on March 1, 2010.
|
/s/ Richard H.
Bachmann
|
/s/ W. Randall
Fowler
|
||
|
Name:
|
Richard
H. Bachmann
|
Name:
|
W.
Randall Fowler
|
|
Title:
|
Chief
Executive Officer of
|
Title:
|
Chief
Financial Officer of
|
|
our
general partner,
|
our
general partner,
|
||
|
DEP
Holdings, LLC
|
DEP
Holdings, LLC
|
||
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of DEP Holdings, LLC and
Unitholders
of Duncan Energy Partners L.P.
Houston,
Texas
We have audited the internal control
over financial reporting of Duncan Energy Partners L.P. and subsidiaries (the
“Company”) as of December 31, 2009, based on criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company’s 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 Annual Report on Internal Control over
Financial Reporting as of December 31, 2009. 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 by, or under the supervision of, the
company's principal executive and principal financial officers, or persons
performing similar functions, and effected by the company's board of directors,
management, and other personnel 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 the inherent limitations of
internal control over financial reporting, including the possibility of
collusion or improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely basis.
Also, projections of any evaluation of the effectiveness of the internal control
over financial reporting to future periods are subject to the risk that the
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009, based on the criteria
established in Internal
Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet and the related
statements of consolidated operations, comprehensive income, cash flows, and
equity as of and for the year ended December 31, 2009 of the Company and our
report dated March 1, 2010 expresses an unqualified opinion on those financial
statements and includes an explanatory paragraph indicating the financial
statements of the Company were prepared from the separate records maintained by
Enterprise Products Partners L.P. or affiliates and may
not necessarily be indicative of
the conditions that would have existed or the results of operations if the
Company had been operated as an unaffiliated entity.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
March 1,
2010
Benefit
Plans Approved by Written Consent
On December 10, 2009, the Board
unanimously approved a resolution adopting both the 2010 Plan and the
EUPP. The 2010 Plan provides for awards of options to purchase common
units, restricted common units, common unit appreciation rights (“UARs”),
phantom units and distribution equivalent rights (“DERs”) to employees,
directors or consultants providing services to us and our
subsidiaries. The Board authorized the issuance of up to 500,000
common units in connection with this plan. The EUPP provides eligible
employees the opportunity to purchase common units at a discount through
withholdings from eligible compensation. The Board authorized the
issuance of up to 500,000 common units in connection with this
plan. On December 30, 2009, the action taken by the Board
regarding the plans was approved by written consent of a subsidiary of EPO,
which held of record approximately 58.6% of our outstanding common units as of
that date. Because EPO’s subsidiary held a majority of our common
units as of December 30, 2009, no other votes were necessary to adopt the
plans. The plans became effective on February 11, 2010.
Partnership
Management
As is commonly the case with publicly
traded limited partnerships, we do not directly employ any of the persons
responsible for the management or operations of our business. These
functions are performed by the employees of EPCO pursuant to the ASA under the
direction of the Board and executive officers of our general
partner. For additional information regarding the ASA, see
“Relationship with EPCO” in Note 15 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
The
executive officers of DEP GP, our general partner, are elected for one-year
terms and may be removed, with or without cause, only by the
Board. Our unitholders do not elect the officers or directors of DEP
GP. Although the members of our Board are elected by EPO, Dan L.
Duncan, through his indirect control of EPO and our general partner, has the
ability to elect, remove and replace at any time, all of the officers and
directors of DEP GP. Each member of the Board of our general partner
serves until such member’s death, resignation or removal. The
employees of EPCO who served as directors of DEP GP during 2009 were Messrs.
Duncan, Bachmann, Creel, Cunningham, Fowler and Teague.
Because we are a limited partnership
and meet the definition of a “controlled company” under the listing standards of
the NYSE, we are not required to comply with certain requirements of the NYSE.
Accordingly, we have elected to not comply with Section 303A.01 of the NYSE
Listed Company Manual, which would require that the Board be comprised of a
majority of independent directors. In addition, we have elected to
not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company
Manual, which would require that the Board maintain a Nominating Committee and a
Compensation Committee, each consisting entirely of independent
directors.
Notwithstanding any contractual
limitation on its obligations or duties, DEP GP is liable for all debts we incur
(to the extent not paid by us), except to the extent that such indebtedness or
other obligations are non-recourse to DEP GP. Whenever possible, DEP
GP intends to make any such indebtedness or other obligations non-recourse to
itself.
Under our
limited partnership agreement and subject to specified limitations, we will
indemnify to the fullest extent permitted by Delaware law, from and against all
losses, claims, damages or similar events, any director or officer, or while
serving as director or officer, any person who is or was serving as a tax
matters member or as a director, officer, tax matters member, employee, partner,
manager, fiduciary or trustee of our partnership or any of our
affiliates. Additionally, we will indemnify to the fullest extent
permitted by law, from and against all losses, claims, damages or similar
events, any person who is or was an employee (other than an officer) or agent of
our general partner.
Corporate
Governance
We are
committed to sound principles of governance. Such principles are
critical for us to achieve our performance goals and maintain the trust and
confidence of investors, employees, suppliers, business partners and
stakeholders.
A key
element for strong governance is independent members of the
Board. Pursuant to the NYSE listing standards, a director will be
considered independent if the Board determines that he or she does not have a
material relationship with us or our general partner (either directly or as a
partner, unitholder or officer of an organization that has a material
relationship with us or our general partner). Based on the foregoing, the Board
has affirmatively determined that William A. Bruckmann, III,
Larry J. Casey, Joe D. Havens and Richard S. Snell are
“independent” directors under the NYSE rules. In making its
determination, the Board’s considerations included the fact that Mr. Havens sold
(i) 75,865 units of Enterprise GP Holdings L.P. at $19.68 per unit and 100,000
common units of Enterprise Products Partners L.P. at $22.15 per unit to
affiliates of Mr. Duncan on February 9, 2009 and (ii) 99,453 units of Duncan
Energy Partners L.P. at $15.58 per unit to affiliates of Mr. Duncan on June 23,
2009. The Board’s considerations also included the fact that Mr.
Duncan has guaranteed outstanding personal bank loans in the aggregate principal
amount of $350,000 for which Mr. Casey is the primary obligor. The
proceeds of the loans were used by Mr. Casey to purchase a total of 10,900 of
our common units in December 2008 and a total of 6,600 common units of
Enterprise Products Partners in December 2007, in each case, at prevailing
market prices. The units are pledged as collateral to secure the
loans.
Code
of Conduct and Ethics and Corporate Governance Guidelines
DEP GP
has adopted a “Code of Conduct” that applies to its directors, officers and
employees. This code sets out our requirements for compliance with legal and
ethical standards in the conduct of our business, including general business
principles, legal and ethical obligations, compliance policies for specific
subjects, obtaining guidance, the reporting of compliance issues and discipline
for violations of the code. The Code of Conduct also establishes
policies applicable to our chief executive officer, chief financial officer,
principal accounting officer and senior financial and other managers to prevent
wrongdoing and to promote honest and ethical conduct, including ethical handling
of actual and apparent conflicts of interest, compliance with applicable laws,
rules and regulations, full, fair, accurate, timely and understandable
disclosure in public communications and prompt internal reporting of violations
of the code (and thus accountability for adherence to the code).
Governance guidelines, together with
committee charters, provide the framework for effective
governance. The Board has adopted the “Governance Guidelines of
Duncan Energy Partners,” which address several matters, including qualifications
for directors, responsibilities of directors, retirement of directors, the
composition and responsibility of the Audit, Conflicts and Governance (“ACG”)
Committee, the conduct and frequency of board and committee meetings, management
succession, director access to management and outside advisors, director
compensation, director and executive officer equity ownership, director
orientation and continuing education, and annual self-evaluation of the
board. The Board
recognizes
that effective governance is an on-going process, and thus, the Board will
review the Governance Guidelines of Duncan Energy Partners annually or more
often as deemed necessary.
We provide access through our website
at www.deplp.com to
current information relating to governance, including the Code of Conduct, the
Governance Guidelines of Duncan Energy Partners and other matters impacting our
governance principles. You may also contact our Investor Relations department at
(866) 230-0745 for printed copies of these documents free of
charge.
ACG
Committee
The sole
committee of the Board is its ACG Committee. In accordance with NYSE
rules and Section 3(a)(58)(A) of the Securities Exchange Act of 1934, the
Board has named four of its members to serve on its ACG
Committee. The members of the ACG Committee are independent
directors, free from any relationship with us or any of our subsidiaries that
would interfere with the exercise of independent judgment.
The
members of the ACG Committee must have a basic understanding of finance and
accounting and be able to read and understand fundamental financial statements,
and at least one member of the ACG Committee shall have accounting or related
financial management expertise. The members of the ACG Committee are
Messrs. Bruckmann, Casey, Havens and Snell. The Board has
affirmatively determined that Mr. Bruckmann satisfies the definition of
“audit committee financial expert” as defined in Item 407(d) of Regulation S-K
promulgated by the SEC.
The ACG
Committee’s duties are addressing audit and conflicts-related items and general
corporate governance matters. From an audit and conflicts standpoint,
the primary responsibilities of the ACG Committee include:
|
§
|
review
potential conflicts of interest, including related party
transactions;
|
|
§
|
monitoring
the integrity of our financial reporting process and related systems of
internal control;
|
|
§
|
ensuring
our legal and regulatory compliance and that of DEP
GP;
|
|
§
|
overseeing
the independence and performance of our independent public
accountant;
|
|
§
|
approving
all services performed by our independent public
accountant;
|
|
§
|
providing
for an avenue of communication among the independent public accountant,
management, internal audit function and the
Board;
|
|
§
|
encouraging
adherence to and continuous improvement of our policies, procedures and
practices at all levels;
|
|
§
|
reviewing
areas of potential significant financial risk to our businesses;
and
|
|
§
|
approving
awards granted under our long-term incentive
plans.
|
If the
Board believes that a particular matter presents a conflict of interest and
proposes a resolution, the ACG Committee has the authority to review such matter
to determine if the proposed resolution is fair and reasonable to
us. Any matters approved by the ACG Committee are conclusively deemed
to be fair and reasonable to our business, approved by all of our partners and
not a breach by DEP GP or the Board of any duties they may owe us or our
unitholders.
Pursuant to its formal written charter,
the ACG Committee has the authority to conduct any investigation appropriate to
fulfilling its responsibilities, and it has direct access to our independent
public accountants as well as any EPCO personnel whom it deems necessary in
fulfilling its responsibilities. The
ACG
Committee has the ability to retain, at our expense, special legal, accounting
or other consultants or experts it deems necessary in the performance of its
duties.
From a
governance standpoint, the primary duties and responsibilities of the ACG
Committee are to recommend to the Board a set of governance principles
applicable to us and review such guidelines from time to time, making any
changes that the ACG Committee deems necessary. The ACG Committee
assists the Board in fulfilling its oversight responsibilities.
A copy of
the ACG Committee charter is available on our website, www.deplp.com. You
may also contact our Investor Relations department at (866) 230-0745 for a
printed copy of this document free of charge.
NYSE
Corporate Governance Listing Standards
On March
20, 2009, Richard H. Bachmann, our Chief Executive Officer, certified to the
NYSE (as required by Section 303A.12(a) of the NYSE Listed Company Manual) that
he was not aware of any violation by us of the NYSE’s Corporate Governance
listing standards as of March 20, 2009.
Executive
Sessions of Non-Management Directors
The Board
holds regular executive sessions in which non-management directors meet without
any members of management present. The purpose of these executive
sessions is to promote open and candid discussion among the non-management
directors. During such executive sessions, one director is designated
as the “presiding director,” who is responsible for leading and facilitating
such executive sessions. Currently, the presiding director is Mr.
Bruckmann.
In
accordance with NYSE rules, we have established a toll-free, confidential
telephone hotline (the “Hotline”) so that interested parties may communicate
with the presiding director or with all the non-management directors as a
group. All calls to this Hotline are reported to the chairman of the
ACG Committee, who is responsible for communicating any necessary information to
the other non-management directors. The number of our confidential
Hotline is (877) 888-0002.
Directors
and Executive Officers of DEP GP
The
following table sets forth the name, age and position of each of the directors
and executive officers of our general partner at March 1, 2010.
|
Name
|
Age
|
Position
with DEP GP
|
|||
|
Dan
L. Duncan (1)
|
77 |
Director
and Chairman
|
|||
|
Richard
H. Bachmann (1)
|
57 |
Director,
President and Chief Executive Officer
|
|||
|
W.
Randall Fowler (1)
|
53 |
Director,
Executive Vice President and Chief Financial Officer
|
|||
|
A.
James Teague (1)
|
64 |
Director,
Executive Vice President and Chief Commercial Officer
|
|||
|
Michael
A. Creel
|
56 |
Director
|
|||
|
Dr.
Ralph S. Cunningham
|
69 |
Director
|
|||
|
Larry
J. Casey (2)
|
77 |
Director
|
|||
|
Joe
D. Havens (2)
|
80 |
Director
|
|||
|
William
A. Bruckmann, III (2,3)
|
58 |
Director
|
|||
|
Richard
S. Snell (2)
|
67 |
Director
|
|||
|
William
Ordemann (1)
|
50 |
Executive
Vice President
|
|||
|
Bryan
F. Bulawa (1)
|
40 |
Senior
Vice President and Treasurer
|
|||
|
Michael
J. Knesek (1)
|
55 |
Senior
Vice President, Principal Accounting Officer and
Controller
|
|||
|
(1)
Executive
Officer
(2)
Member
of ACG Committee
(3)
Chairman
of ACG Committee
|
|||||
The following information presents a
brief history of the business experience of the directors and executive officers
of DEP GP serving as of March 1, 2010.
Dan L.
Duncan. Mr.
Duncan was elected Chairman and a Director of DEP GP in October 2006, Chairman
and a Director of EPE Holdings in August 2005, Chairman and a Director of the
general partner (now the managing member) of EPO in December 2003 and Chairman
and a Director of EPGP in April 1998. Mr. Duncan served as the sole
Chairman of EPCO from 1979 to December 2007. Mr. Duncan now serves as
Group Co-Chairman of EPCO with his daughter, Ms. Randa Duncan Williams, who is
also a director of EPE Holdings. In December 2009, Mr. Duncan was
appointed as a Director of LE GP. He also serves as an Honorary
Trustee of the Board of Trustees of the Texas Heart Institute at Saint Luke’s
Episcopal Hospital and on the Board of Trustees of the Baylor College of
Medicine.
Richard
H. Bachmann. Mr. Bachmann was elected President, Chief Executive Officer
and a Director of DEP GP in October 2006 and a Director of EPE Holdings and EPGP
in February 2006. Mr. Bachmann previously served as a Director
of EPGP from June 2000 to January 2004. Mr. Bachmann has served as
Executive Vice President, Chief Legal Officer and Secretary of EPE Holdings
since April 2005. Mr. Bachmann was elected Executive Vice
President and Chief Legal Officer of EPGP in February 1999 and Secretary of EPGP
in November 1999. Mr. Bachmann has served as a director of EPCO since
January 1999, as Executive Vice President and Chief Legal Officer of EPCO since
May 1999 and as Group Vice Chairman of EPCO since December 2007. In
November 2006, Mr. Bachmann was appointed as an independent manager of
Constellation Energy Partners LLC. Mr. Bachmann also serves as a member of
the Audit, Compensation and Nominating and Governance committees of
Constellation Energy Partners LLC and as the chairman of its Conflicts
Committee.
W. Randall
Fowler. Mr.
Fowler was elected Executive Vice President and Chief Financial Officer of DEP
GP, EPE Holdings and EPGP in August 2007. Mr. Fowler has served as a
Director of DEP GP since September 2006 and EPE Holdings and EPGP since February
2006. Mr. Fowler served as a Senior Vice President and Treasurer of
DEP GP from October 2006 to August 2007. Mr. Fowler served as Senior
Vice President and Treasurer of EPGP from February 2005 to August
2007. Mr. Fowler also served as Senior Vice President and Chief
Financial Officer of EPE Holdings from August 2005 to August
2007. Mr. Fowler was elected President and Chief Executive
Officer of EPCO in December 2007. Prior to these elections, he served
as Chief Financial Officer of EPCO from April 2005 to December
2007. Mr. Fowler, a certified public accountant (inactive),
joined Enterprise Products Partners as Director of Investor Relations in January
1999. Mr. Fowler also serves as Chairman of the Board of the National
Association of Publicly Traded Partnerships.
A. James
Teague. Mr. Teague was elected a Director of DEP GP and
Executive Vice President and Chief Commercial Officer in July
2008. He also serves as a Director of EPE Holdings (since October
2009) and a Director of EPGP (since July 2008). Mr. Teague joined the
EPCO family of companies in connection with Enterprise Products Partners’
acquisition of certain midstream energy assets from affiliates of Shell Oil
Company in 1999. Mr. Teague was elected an Executive Vice President
of EPGP in November 1999. From 1998 to 1999, Mr. Teague served as
President of Tejas Natural Gas Liquids, LLC, then an affiliate of
Shell. From 1997 to 1998, he was President of Marketing and Trading
for Mapco Inc.
Michael
A. Creel. Mr. Creel was elected a Director of DEP GP in
October 2006. From October 2006 to August 2007, Mr. Creel served as
the Chief Financial Officer and an Executive Vice President of DEP
GP. In August 2007, Mr. Creel resigned these positions with DEP GP
and was appointed President and Chief Executive Officer of EPGP.
Mr. Creel, a certified public
accountant, has held various senior and executive management positions within
the EPCO group of companies since November 1999. Apart from his
current position as President and Chief Executive Officer of EPGP and a Director
of DEP GP, Mr. Creel also serves as Chief Financial Officer of EPCO (since
December 2007) and a Director of EPGP (since February 2006) and as a Director of
EPE Holdings (since October 2009). Mr. Creel served as President,
Chief Executive Officer and a Director of EPE Holdings from August 2005 through
August 2007. From October 2005 through December 2009, Mr. Creel
served as a Director of Edge Petroleum Corporation, a publicly traded oil and
natural gas exploration and production company, which filed a voluntary petition
under Chapter 11 of the U.S. Bankruptcy Code in October 2009 and, on December
31, 2009, completed the sale of substantially all of its assets to Mariner
Energy, Inc.
Dr. Ralph
S. Cunningham. Dr. Cunningham
was elected a Director of DEP GP in August 2007. In addition to these
duties, Dr. Cunningham has served as the President and Chief Executive Officer
and a Director of EPE Holdings since August 2007 and a Director of EPGP since
February 2006. He served as Group Executive Vice President and Chief
Operating Officer of EPGP from December 2005 to August 2007 and Interim
President and Interim Chief Executive Officer from June 2007 to August
2007. Dr. Cunningham also served as a Director of EPGP from 1998 to
March 2005 and as Chairman and a Director of TEPPCO GP from March 2005 until
November 2005.
Dr.
Cunningham was elected a Group Vice Chairman of EPCO in December 2007 and served
as a Director from 1987 to 1997. He serves as a Director of Tetra
Technologies, Inc. (a publicly traded energy services and chemical company), LE
GP and Agrium, Inc. (a Canadian publicly traded agricultural chemicals
company). In addition, Dr. Cunningham serves as a Director and the
Chairman of the Safety, Health and Responsibility Committee of Cenovus Energy
Inc. (a Canadian publicly traded oil company). Dr. Cunningham retired
in 1997 from CITGO Petroleum Corporation, where he had served as President and
Chief Executive Officer since 1995.
Larry J.
Casey. Mr.
Casey was elected a Director of DEP GP in October 2006. Mr. Casey has
been a private investor managing real estate and personal investments since he
retired in 1982 from a career in the energy industry. In 1974,
Mr. Casey founded Xcel Products Company, an NGL and petrochemical trading
company. Also in 1974, he founded Xral Underground Storage, the first
privately owned underground merchant storage facility for NGLs and specialty
chemicals at Mont Belvieu, Texas. Mr. Casey sold these companies in 1982.
Mr. Casey serves on our ACG Committee.
Joe D.
Havens.
Mr. Havens was elected a Director of DEP GP in October 2006. Mr.
Havens has been an entrepreneur engaged in the energy, banking and real estate
industries. Mr. Havens founded Enterprise Petroleum Company,
Inc., the predecessor to EPCO, in 1968, and sold his interest in the successor
entity and related businesses to Mr. Duncan in
1990. Mr. Havens also served on the board of Directors of the
First Commerce Bank of Corpus Christi, a private bank, from 1991, until he sold
his interest in such bank in 2007. Mr. Havens serves on our ACG
Committee.
William
A. Bruckmann, III. Mr. Bruckmann was elected a Director
of DEP GP in October 2006. Mr. Bruckmann has been self-employed as a
consultant and private investor since April 2004. From September 2002
to April 2004, Mr. Bruckmann served as a financial advisor with
UBS Securities, Inc. He is a former managing Director at Chase Securities,
Inc. and has more than 25 years of banking experience, starting with
Manufacturers Hanover Trust Company, where he became a senior officer in 1985.
Mr. Bruckmann later served as Managing Director, sector head of
Manufacturers Hanover’s gas pipeline and midstream energy practices through the
acquisition of Manufacturers Hanover by Chemical Bank and the acquisition of
Chemical Bank by Chase Bank. Mr. Bruckmann also served as a
Director of Williams Energy Partners L.P. from May 2001 to
June 2003. Mr. Bruckmann serves on our ACG Committee as its
Chairman.
Richard
S. Snell. Mr. Snell, a certified public accountant, was
elected a Director of DEP GP in January 2010. Mr. Snell most recently
served as a director of TEPPCO GP from January 2006 until TEPPCO’s merger with a
subsidiary of Enterprise Products Partners in October 2009. From June
2000 until February 2006, he served as a director of EPGP. He has
been a partner with the law firm of Thompson & Knight LLP since May
2000. Prior to his position with Thompson & Knight LLP, he worked
as an attorney for the Snell & Smith, P.C. law firm from its founding in
1993 until May 2000. Mr. Snell serves on our ACG
Committee.
William
Ordemann. Mr. Ordemann was elected an Executive Vice President
of DEP GP in August 2007. He was elected Chief Operating Officer and
Executive Vice President of EPGP in August 2007. He previously served
as a Senior Vice President of EPGP from September 2001 to August 2007 and one of
its Vice Presidents from October 1999 to September 2001. Prior to
joining Enterprise Products Partners, Mr. Ordemann held senior management
positions at Shell Midstream Enterprises, LLC and Tejas Natural Gas Liquids,
LLC, both of which were affiliates of Shell Oil Company.
Bryan F.
Bulawa. Mr.
Bulawa was elected Senior Vice President and Treasurer of EPGP, EPE Holdings and
DEP GP in October 2009, having served as Vice President and Treasurer of EPGP
since July 2007. Prior to joining Enterprise, Mr. Bulawa spent 13
years at Scotia Capital, where he served as director of the firm’s U.S. Energy
Corporate Finance and Distribution group.
Michael
J. Knesek. Mr. Knesek, a certified
public accountant, was elected Senior Vice President, Principal Accounting
Officer and Controller of DEP GP in September 2006. Mr. Knesek has
been the Principal Accounting Officer and Controller of EPGP since August 2000
and of EPE Holdings since August 2005. He also serves as a Senior
Vice President of EPGP (since February 2005) and EPE Holdings (since August
2005). He previously served as Vice President of EPGP from August
2000 to February 2005. Mr. Knesek has been the Controller and a
Vice President of EPCO since 1990.
Director
Experience, Qualifications, Attributes and Skills
The following is a brief discussion of
the experience, qualifications, attributes or skills that led to the conclusion
that the following persons should serve as a director of our general
partner.
Six of our directors are employees of
EPCO and officers of our general partner or its affiliates. Each of
these directors has significant experience in our industry as executive officers
as well as other qualifications, attributes and skills. These
include: for Mr. Duncan, over 55 years of ownership and management of a number
of midstream businesses, including as one of the founders of Enterprise Products
Partners; for Mr. Bachmann, over 28 years of experience with our midstream
assets, including legal, regulatory, contract and merger and acquisitions and,
for over the last ten years, as a member of Enterprise Products Partners’
executive management team; for Mr. Fowler, over ten years of experience with our
midstream assets, including finance, accounting (inactive certified public
accountant) and investor public relations and, for over the last six years, as a
member of Enterprise Products Partners’ executive management team; for Mr.
Teague, over 40 years of commercial management of midstream assets and marketing
and trading activities, both for third parties and for the Enterprise Products
Partners’ businesses; for Mr. Creel, over 30 years of management experience with
midstream assets, for both third parties and Enterprise Products Partners,
including finance and accounting (certified public accountant) and more than six
years of management experience in the financial industry; and for Dr.
Cunningham, over 45 years of refined products, chemicals, and midstream
businesses.
Our four outside directors also have
significant experience in our industry in a variety of capacities, as well as
other qualifications, attributes and skills. These include: for Mr.
Casey, executive management of NGL and petrochemicals trading, and related
storage businesses; for Mr. Havens, entrepreneur and one of the co-founders,
along with Mr. Duncan, of the predecessor company to Enterprise Products
Partners; for Mr. Bruckmann, investment banking, including financial advisory,
commercial banking, and working with complex financial statements; and for Mr.
Snell, legal, review of accounting and financial statements and director
oversight functions for other midstream assets of our affiliates.
Section
16(a) Beneficial Ownership Reporting Compliance
Under the federal securities laws, DEP
GP, directors and executive officers of DEP GP and any persons holding more than
10% of our common units are required to report their beneficial ownership of
common units and any changes in that ownership to us and the
SEC. Specific due dates for these reports have been established by
regulation, and we are required to disclose in this annual report any failure to
file by these dates during 2009. All such reporting was done in a
timely manner in 2009, except that on February 26, 2009, Mr. Havens filed a late
Form 4 reporting two purchase transactions that he inadvertently failed to
timely report during 2008. In addition, on February 11, 2010, Mr.
Havens filed a late Form 4 reporting one purchase transaction (executed on
February 8, 2010) that he inadvertently failed to report by the reporting
deadline on February 10, 2010.
We do not directly employ any of the
persons responsible for managing our partnership. Instead, we are
managed by our general partner, the executive officers of which are employees of
EPCO, a privately held company controlled by Dan L. Duncan. Our
management, administrative and operating functions are primarily performed by
employees of EPCO pursuant to the ASA. Pursuant to the ASA, we
reimburse EPCO for 100% of EPCO’s compensation costs related to our
partnership. For additional information regarding the ASA, see Note
15 of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report.
Summary
Compensation Table
The following table presents total
compensation amounts paid, accrued or otherwise expensed by us with respect to
the years ended December 31, 2009, 2008 and 2007 for the chief executive
officer, chief financial officer and three other most highly compensated
executive officers of our general partner as of December 31,
2009. Collectively, these five individuals were our “named executive
officers” for 2009.
|
Cash
|
Cash
|
Unit
|
Option
|
All
Other
|
|||||||||||||||||||||
|
Name
and
|
Salary
|
Bonus
|
Awards
|
Awards
|
Comp.
|
Total
|
|||||||||||||||||||
|
Principal
Position
|
Year
|
($)
|
($)
(1)
|
($)
(2)
|
($)
(3)
|
($)
(4)
|
($)
|
||||||||||||||||||
|
Richard
H. Bachmann
|
2009
|
$ | 129,000 | $ | 190,000 | $ | 550,867 | $ | 133,080 | $ | 47,295 | $ | 1,050,242 | ||||||||||||
|
(President
and Chief Executive Officer)
|
2008
|
159,688 | 106,250 | 972,925 | 35,700 | 59,055 | 1,333,618 | ||||||||||||||||||
|
2007
|
71,508 | 43,338 | 284,979 | 18,733 | 22,077 | 440,635 | |||||||||||||||||||
|
W.
Randall Fowler
|
2009
|
55,781 | 95,625 | 262,684 | 65,416 | 21,660 | 501,166 | ||||||||||||||||||
|
(Executive
Vice President and
|
2008
|
63,594 | 43,750 | 459,152 | 17,850 | 20,882 | 605,228 | ||||||||||||||||||
|
Chief
Financial Officer)
|
2007
|
22,675 | 13,800 | 112,337 | 6,295 | 5,684 | 160,791 | ||||||||||||||||||
|
A.
J. Teague (5)
|
2009
|
162,500 | 237,500 | 611,396 | 166,350 | 58,437 | 1,236,183 | ||||||||||||||||||
|
(Executive
Vice President and
|
|||||||||||||||||||||||||
|
Chief
Commercial Officer)
|
|||||||||||||||||||||||||
|
William
Ordemann (6)
|
2009
|
63,232 | 49,600 | 262,919 | 90,552 | 35,275 | 501,578 | ||||||||||||||||||
|
(Executive
Vice President)
|
2008
|
15,656 | 10,600 | 71,192 | 5,712 | 6,314 | 109,474 | ||||||||||||||||||
|
Michael
J. Knesek
|
2009
|
50,700 | 27,625 | 158,996 | 54,064 | 17,099 | 308,484 | ||||||||||||||||||
|
(Senior
Vice President, Controller
|
2008
|
61,800 | 26,000 | 185,478 | 14,280 | 21,200 | 308,758 | ||||||||||||||||||
|
and
Principal Accounting Officer)
|
2007
|
22,089 | 9,000 | 69,381 | 6,030 | 5,814 | 112,314 | ||||||||||||||||||
|
(1)
Amounts
represent discretionary annual cash awards accrued with respect to the
years presented. Cash awards are paid in February of the following
year (e.g., the cash awards for 2009 were paid in February
2010).
(2)
Amounts
represent the aggregate grant date fair value of restricted unit and
Employee Partnership profits interests awards granted during each year
presented. For information about assumptions made in the valuation of
these awards, see Note 5 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report, which information is
incorporated by reference herein.
(3)
Amounts
represent the aggregate grant date fair value of unit option awards
granted during each year presented. For information about assumptions
made in the valuation of these awards, see Note 5 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report, which information is incorporated by reference
herein.
(4)
Amounts
primarily represent (i) matching contributions under funded, qualified,
defined contribution retirement plans, (ii) quarterly distributions paid
on incentive plan awards and (iii) the imputed value of life insurance
premiums paid on behalf of the officer.
(5)
Mr.
Teague was elected our Chief Commercial Officer in July 2008. Mr.
Teague devoted a minimal amount of his time to our business activities
during 2008 and instead indirectly supervised the activities of other
personnel who were more directly involved in our affairs.
(6)
Mr.
Ordemann devoted a minimal amount of his time to our business activities
during 2007 and instead indirectly supervised the activities of other
personnel who were more directly involved in our affairs. As a
result, Mr. Ordemann allocated a nominal amount of his compensation to us
in 2007.
|
|||||||||||||||||||||||||
Each of the named executive officers
continues to perform services for Enterprise Products Partners and other
affiliates of EPCO. Our named executive officers devote less than a
majority of their time to our matters and allocate less than a majority of their
compensation to us. Under the ASA, the compensation costs of our
named executive officers are allocated to us and our affiliates based on the
estimated amount of time that each officer spends on our consolidated businesses
in any fiscal year. These percentages are reassessed at least
quarterly.
The following table presents the
average approximate amount of time devoted by each of our named executive
officers to our consolidated businesses and those of our other affiliates for
each of the years presented.
|
Duncan
|
EPCO
and
|
Total
|
|||||||||||
|
Energy
|
other
|
Time
|
|||||||||||
|
Named
Executive Officer
|
Year
|
Partners
|
affiliates
|
Allocated
|
|||||||||
|
Richard
H. Bachmann (CEO)
|
2009
|
20% | 80% | 100% | |||||||||
|
2008
|
25% | 75% | 100% | ||||||||||
|
2007
|
12% | 88% | 100% | ||||||||||
|
W.
Randall Fowler (CFO)
|
2009
|
11% | 89% | 100% | |||||||||
|
2008
|
12% | 88% | 100% | ||||||||||
|
2007
|
5% | 95% | 100% | ||||||||||
|
A.
James Teague
|
2009
|
25% | 75% | 100% | |||||||||
|
William
Ordemann
|
2009
|
16% | 84% | 100% | |||||||||
|
2008
|
4% | 96% | 100% | ||||||||||
|
Michael
J. Knesek
|
2009
|
16% | 84% | 100% | |||||||||
|
2008
|
20% | 80% | 100% | ||||||||||
|
2007
|
8% | 92% | 100% | ||||||||||
Our named executive officers did not
specifically allocate any of their time to the DEP I or DEP II Midstream
Businesses prior to the respective drop down transactions in February 2007 and
December 2008, respectively. As a result, we cannot indicate the
historical salaries or other elements of compensation that would have been
allocated to us pursuant to the ASA had these businesses been owned by us for
all periods presented.
Compensation
Discussion and Analysis
With respect to our named executive
officers, compensation paid or awarded by us for the last three fiscal years
reflects only that portion of compensation paid by EPCO allocated to us pursuant
to the ASA, including an allocation of a portion of the cost of equity-based
long-term incentive plans of EPCO. Dan L. Duncan controls EPCO and
has ultimate decision-making authority with respect to the compensation of our
named executive officers. The following elements of compensation, and
EPCO’s decisions with respect to determination of payments, are not subject to
approvals by the Board or the ACG Committee of our general
partner. Equity awards under EPCO’s long-term incentive plans are
approved by the ACG Committee of the respective issuer. We do not
have a separate compensation committee.
As discussed below, the elements of
EPCO’s compensation program, along with EPCO’s other rewards (e.g., benefits,
work environment and career development), are intended to provide a total
rewards package to employees. The objectives of EPCO’s compensation
program are to provide competitive compensation opportunities that will align
and drive employee performance toward the creation of sustained long-term
unitholder value. Our compensation program allows us to attract,
motivate and retain high quality talent with the skills and competencies we
require. The compensation package is designed to reward contributions
by employees in support of the business strategies of EPCO and its affiliates at
both the partnership and individual levels. With respect to the three
years ended December 31, 2009, EPCO’s compensation package for named executive
officers did not include any elements based on targeted performance-related
criteria.
The primary elements of EPCO’s
compensation program are a combination of annual cash and long-term equity-based
incentive compensation. For the three years ended December 31, 2009, the
elements of compensation for the named executive officers consisted of the
following:
|
§
|
Annual
cash base salary;
|
|
§
|
Discretionary
annual cash bonus awards;
|
|
§
|
Awards
under long-term incentive arrangements;
and
|
|
§
|
Other
compensation, including very limited
perquisites.
|
In order to assist Mr. Duncan and EPCO
with compensation decisions, Mr. Creel and Dr. Cunningham (both Group Vice
Chairmen for EPCO) and the senior vice president of Human Resources for EPCO
formulate preliminary compensation recommendations for the named executive
officers that are at the executive vice president level and
above. Mr. Duncan, after consulting with the senior vice president of
Human Resources for EPCO, independently makes compensation decisions with
respect to the named executive officers at the executive vice president level
and above. With respect to our named executive officer that is a
senior vice president, Messrs. Creel and Cunningham, after consultation with the
senior vice president of Human Resources for EPCO, make compensation decisions
regarding such individual. In making these compensation decisions,
EPCO considers market data for determining relevant compensation levels and
compensation program elements through the review of and, in certain cases,
participation in, relevant compensation surveys and reports. These
surveys and reports are conducted and prepared by a third-party compensation
consultant.
Periodically, EPCO will engage a
third-party consultant to review compensation elements provided to our executive
officers. In 2009, EPCO engaged Hewitt & Associates (“Hewitt”) to
review executive compensation relative to our industry. Hewitt
provided comparative market data on compensation practices and programs for
executive level positions based on an analysis of industry competitors and
external trends. Neither we, nor EPCO, which engages the consultant,
are aware of the identity of the companies whose data was used from the
consultant’s proprietary data base for specific positions. EPCO uses
the information provided in the Hewitt analysis to gauge whether compensation
levels reported by the consultant are within the general ranges of compensation
for EPCO employees in similar positions, but that comparison is only a factor
taken into consideration and may or may not impact compensation of our executive
officers, for which Dan L. Duncan has the ultimate decision-making
authority. EPCO does not otherwise engage in benchmarking for the
named executive officers’ positions.
Mr. Duncan and EPCO do not use any
formula or specific performance-based criteria for our named executive officers
in connection with determining compensation for services performed for us;
rather, Mr. Duncan and EPCO determine an appropriate level and mix of
compensation on a case-by-case basis. Further, there is no
established policy or target for the allocation between either cash and non-cash
or short-term and long-term incentive compensation. However, some
considerations that Mr. Duncan may take into account in making the case-by-case
compensation determinations include total value of all elements of compensation
and the appropriate balance of internal pay equity among executive
officers. Mr. Duncan and EPCO also consider individual performance,
levels of responsibility and value to the organization. All
compensation determinations are discretionary and, as noted above, subject to
Mr. Duncan’s ultimate decision-making authority, except for equity awards under
EPCO’s long-term incentive plans, as discussed below.
We believe the absence of specific
performance-based criteria associated with our cash compensation and equity
awards, and the long-term nature of our equity awards, has the effect of
discouraging excessive risk taking by our executive officers in order to reach
certain targets. Further, the practice of making compensation decisions on a
case-by-case basis permits consideration of flexible criteria, including current
overall market conditions.
The discretionary cash bonus awards
paid to each of our named executive officers were determined by consultation, as
appropriate, among Mr. Duncan, Mr. Creel, Dr. Cunningham, Mr. Bachmann and the
senior vice president of Human Resources for EPCO, subject to Mr. Duncan’s final
determination. These cash bonus awards, in combination with annual
base salaries, are intended to yield competitive total cash compensation levels
for the named executive officers and drive performance in support of our
business strategies, as well as the performance of other EPCO affiliates for
which the named executive officers perform services. It is EPCO’s
general policy to pay these awards in February of the following
year.
The awards granted under EPCO’s
long-term incentive plans to our named executive officers were determined by
consultation among Mr. Duncan, Mr. Creel and the senior vice president of Human
Resources for EPCO, and were approved by the ACG Committee of the respective
issuer. In addition, our named executive officers are Class B limited
partners in certain of the Employee Partnerships. Mr. Duncan approves
the issuance of all limited partnership interests in the Employee Partnerships
to our named executive officers. See “Summary of Long-Term Incentive
Arrangements Underlying 2009 Award Grants” below for information regarding
EPCO’s long-term incentive plans.
EPCO generally does not pay for
perquisites for any of our named executive officers, other than reimbursement of
certain parking expenses, and expects to continue its policy of covering limited
perquisites allocable to our named executive officers. EPCO also
makes matching contributions under its defined contribution plans for the
benefit of our named executive officers in the same manner as it does for other
EPCO employees.
EPCO does not offer our named executive
officers a defined benefit pension plan. Also, none of our named
executive officers had nonqualified deferred compensation during the three years
ended December 31, 2009.
In December 2009, EPCO and the partners
of each of the Employee Partnerships amended the partnership agreement of each
of the Employee Partnerships to provide that the expected liquidation date for
such Employee Partnership will be in February 2016. The extensions of
the expected liquidation dates were intended to align the interests of the
employee partners of the Employee Partnerships with the long-term interests of
EPCO and other unitholders in the relevant underlying publicly traded
partnerships, which also hold indirectly a significant ownership interest in
both us and our subsidiaries.
Also in December 2009, the Board
implemented certain equity ownership guidelines for directors and executive
officers of our general partner in order to further align their interests and
actions with the interests of our partnership and its
unitholders. See “Security Ownership of Management” within Item 12 of
this annual report for additional information. Our compensation
practices for our named executive officers are not expected to be impacted by
this new policy.
We believe that each of the base
salary, cash bonus awards, and long-term incentive awards fit the overall
compensation objectives of us and of EPCO and are designed to avoid risks that
are likely to conflict with the partnership’s risk management
policies.
Grants
of Plan-Based Awards in Fiscal Year 2009
The following table presents
information concerning each grant of a plan-based award made to a named
executive officer in 2009 for which we will be allocated by EPCO our pro rata
share under the ASA. The restricted unit and unit option awards granted during
2009 were under EPCO’s long-term incentive plans. See “Summary of Long-Term
Incentive Arrangements Underlying 2009 Award Grants” within this discussion of
compensation of directors and executive officers for additional information
regarding the long-term incentive plans under which these awards were
granted.
|
Grant
|
|||||||||||||||||||||
|
Exercise
|
Date
Fair
|
||||||||||||||||||||
|
or
Base
|
Value
of
|
||||||||||||||||||||
|
Estimated
Future Payouts Under
|
Price
of
|
Unit
and
|
|||||||||||||||||||
|
Equity
Incentive Plan Awards
|
Option
|
Option
|
|||||||||||||||||||
|
Grant
|
Threshold
|
Target
|
Maximum
|
Awards
|
Awards
|
||||||||||||||||
|
Name
|
Date
|
(#) | (#) | (#) |
($/Unit)
|
($) (1)
|
|||||||||||||||
|
Restricted unit
awards: (2)
|
|||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
5/6/09
|
-- | 37,400 | -- | -- | $ | 186,402 | ||||||||||||||
|
W.
Randall Fowler (CFO)
|
5/6/09
|
-- | 34,000 | -- | -- | 90,024 | |||||||||||||||
|
A.
James Teague
|
5/6/09
|
-- | 37,400 | -- | -- | 233,002 | |||||||||||||||
|
William
Ordemann
|
5/6/09
|
-- | 30,000 | -- | -- | 119,616 | |||||||||||||||
|
Michael
J. Knesek
|
5/6/09
|
-- | 12,500 | -- | -- | 50,619 | |||||||||||||||
|
Unit option awards:
(3)
|
|||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
2/19/09
|
-- | 60,000 | -- | $ | 22.06 | 79,560 | ||||||||||||||
|
5/6/09
|
-- | 60,000 | -- | 24.92 | 53,250 | ||||||||||||||||
|
W.
Randall Fowler (CFO)
|
2/19/09
|
-- | 52,500 | -- | 22.06 | 36,983 | |||||||||||||||
|
5/6/09
|
-- | 60,000 | -- | 24.92 | 28,433 | ||||||||||||||||
|
A.
James Teague
|
2/19/09
|
-- | 60,000 | -- | 22.06 | 99,450 | |||||||||||||||
|
5/6/09
|
-- | 60,000 | -- | 24.92 | 66,900 | ||||||||||||||||
|
William
Ordemann
|
2/19/09
|
-- | 45,000 | -- | 22.06 | 47,736 | |||||||||||||||
|
5/6/09
|
-- | 60,000 | -- | 24.92 | 42,816 | ||||||||||||||||
|
Michael
J. Knesek
|
2/19/09
|
-- | 30,000 | -- | 22.06 | 32,321 | |||||||||||||||
|
5/6/09
|
-- | 30,000 | -- | 24.92 | 21,743 | ||||||||||||||||
|
Profits interest awards:
(4)
|
|||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
12/2/09
|
-- | -- | -- | -- | 364,465 | |||||||||||||||
|
W.
Randall Fowler (CFO)
|
12/2/09
|
-- | -- | -- | -- | 172,660 | |||||||||||||||
|
A.
James Teague
|
12/2/09
|
-- | -- | -- | -- | 378,394 | |||||||||||||||
|
William
Ordemann
|
12/2/09
|
-- | -- | -- | -- | 143,303 | |||||||||||||||
|
Michael
J. Knesek
|
12/2/09
|
-- | -- | -- | -- | 108,377 | |||||||||||||||
|
(1)
Amounts
presented reflect that portion of grant date fair value allocable to us
based on the average percentage of time each named executive officer spent
on our consolidated business activities during 2009. Based on current
allocations, we estimate that the consolidated compensation expense we
record for each named executive officer with respect to these awards will
equal these amounts over the vesting period.
(2)
Awards
granted during 2009 were made under the Enterprise Products 1998 Long-Term
Incentive Plan (“1998 Plan”).
(3)
Awards
granted during 2009 were made under the Amended and Restated 2008
Enterprise Products Long-Term Incentive Plan (“2008 Plan”).
(4)
Awards
represent each named executive officer’s share of the aggregate
incremental fair value resulting from the extension of the liquidation
date (a material modification of the underlying awards) of each Employee
Partnership to February 2016.
|
|||||||||||||||||||||
The grant date fair value amounts
presented in the table are based on certain assumptions and considerations made
by management. See Note 5 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for additional
information regarding our fair value assumptions made in connection with
equity-based compensation.
Summary
of Long-Term Incentive Arrangements Underlying 2009 Award Grants
The following information summarizes
the principal types of awards granted to our named executive officers under
EPCO’s long-term incentive plans. These plans provide for incentive awards to
EPCO’s key employees who perform management, administrative or operational
functions for us or our affiliates.
Awards granted under the 1998 Plan may
be in the form of unit options, restricted units, phantom units and distribution
equivalent rights (“DERs”). Awards granted under the 2008 Plan may be in the
form of unit options, restricted units, phantom units and DERs. As of December
31, 2009, no phantom unit awards, UARs or associated DERs have been granted
under the EPCO plans to the named executive
officers. No
awards with respect to our common units have been granted in connection with
these long-term incentive plans.
As additional long-term incentive
arrangements, EPCO granted its key employees who perform services on behalf of
us, EPCO and other affiliated companies “profits interests” in certain limited
partnerships (the “Employee Partnerships”), which are privately held affiliates
of EPCO. The employees were issued Class B limited partner interests and
admitted as Class B limited partners in the Employee Partnerships without any
capital contributions.
Restricted
unit awards. Restricted unit awards allow recipients to acquire common
units of Enterprise Products Partners (at no cost to the recipient) once a
defined vesting period expires, subject to customary forfeiture provisions. For
awards granted prior to 2010, the restrictions on such awards generally lapse
four years from the date of grant. Beginning in 2010, new restricted unit grants
will vest at a rate of 25% per year beginning one year after the grant
date. The fair value of restricted units is based on the market price
per unit of the underlying security on the date of
grant. Compensation expense is recognized based on the grant date
fair value, net of an allowance for estimated forfeitures. Each recipient is
also entitled to cash distributions equal to the product of the number of
restricted units outstanding for the participant and the cash distribution per
unit paid by the respective issuer.
Unit
option awards. Under the EPCO plans, non-qualified incentive options to
purchase a fixed number of common units of Enterprise Products Partners may be
granted to key employees of EPCO. When issued, the exercise price of each option
grant is equivalent to the market price of the underlying equity on the date of
grant. In general, options granted under the EPCO plans have a vesting period of
four years and remain exercisable for five to ten years, as applicable, from the
date of grant.
The fair value of each unit option is
estimated on the date of grant using the Black-Scholes option pricing model,
which incorporates various assumptions including expected life of the options,
risk-free interest rates, expected distribution yield on Enterprise Products
Partners common units, and expected unit price volatility of Enterprise Products
Partners common units. In general, our assumption of expected life of the
options represents the period of time that the options are expected to be
outstanding based on an analysis of historical option activity. Our selection of
the risk-free interest rate is based on published yields for U.S. government
securities with comparable terms. The expected distribution yield and unit price
volatility is estimated based on several factors, which include an analysis of
our historical unit price volatility and distribution yield over a period equal
to the expected life of the option.
Profits
interests awards. Profits interest awards entitle each holder to
participate in the expected long-term appreciation in value of the equity
securities owned by each Employee Partnership. The Employee Partnerships in
which the named executive officers participate own either units of Enterprise GP
Holdings or Enterprise Products Partners or a combination of both.
Each Employee Partnership has a single
Class A limited partner, which is a privately held indirect subsidiary of EPCO,
and a varying number of Class B limited partners. At formation, the Class A
limited partner either contributes cash or limited partner units it owns to the
Employee Partnership. If cash is contributed, the Employee Partnership uses
these funds to acquire limited partner units on the open market. In general, the
Class A limited partner earns a preferred return (either fixed or variable
depending on the partnership agreement) on its investment (“Capital Base”) in
the Employee Partnership and residual quarterly cash amounts, if any, are
distributed to the Class B limited partners. Upon liquidation, Employee
Partnership assets having a fair market value equal to the Class A limited
partner’s Capital Base, plus any preferred return for the period in which
liquidation occurs, will be distributed to the Class A limited
partner. Any remaining assets will be distributed to the Class B
limited partner(s) as a residual profits interest.
The estimated grant date fair values of
the profits interests awards were determined using a Black-Scholes option
pricing model and reflect adjustments for forfeitures, regrants and other
modifications. The profits interests awards are subject to
forfeiture.
The following table presents each named
executive officer’s share of the total profits interest in the Employee
Partnerships at December 31, 2009:
|
Percentage
Ownership of Class B Interests
|
||||||||||||||||
|
EPE
|
EPE
|
Enterprise
|
EPCO
|
|||||||||||||
|
Named
Executive Officer
|
Unit
I
|
Unit
III
|
Unit
|
Unit
|
||||||||||||
|
Richard
H. Bachmann (CEO)
|
9.3% | 8.9% | 10.3% | 20.0% | ||||||||||||
|
W.
Randall Fowler (CFO)
|
6.2% | 8.9% | 8.2% | 20.0% | ||||||||||||
|
A.
James Teague
|
6.2% | 7.4% | 10.3% | 20.0% | ||||||||||||
|
William
Ordemann
|
3.1% | 5.2% | 8.2% | -- | ||||||||||||
|
Michael
J. Knesek
|
3.1% | 3.7% | 5.1% | -- | ||||||||||||
Equity
Awards Outstanding at December 31, 2009
The following information summarizes
each named executive officer’s long-term incentive awards outstanding at
December 31, 2009. The referenced units in the table below are common
units of Enterprise Products Partners. We expect to be allocated our
pro rata share of the expense associated with such awards under the
ASA. As a result, the gross amounts listed in the table do not
represent the amount of expense we expect to recognize in connection with these
awards.
|
Option
Awards
|
Unit
Awards
|
||||||||||||||||||||||||
|
Number
of
|
Number
of
|
Market
|
|||||||||||||||||||||||
|
Units
|
Units
|
Number
|
Value
|
||||||||||||||||||||||
|
Underlying
|
Underlying
|
Option
|
of
Units
|
of
Units
|
|||||||||||||||||||||
|
Options
|
Options
|
Exercise
|
Option
|
That
Have
|
That
Have
|
||||||||||||||||||||
|
Vesting
|
Exercisable
|
Unexercisable
|
Price
|
Expiration
|
Not
Vested
|
Not
Vested
|
|||||||||||||||||||
|
Name
|
Date
|
(#) | (#) |
($/Unit)
|
Date
|
(#)(2) |
($)(3)
|
||||||||||||||||||
|
Restricted
unit awards:
|
|||||||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
Various
(1)
|
-- | -- | -- | -- | 104,000 | $ | 3,266,640 | |||||||||||||||||
|
W.
Randall Fowler (CFO)
|
Various
(1)
|
-- | -- | -- | -- | 91,100 | 2,861,451 | ||||||||||||||||||
|
A.
James Teague
|
Various
(1)
|
-- | -- | -- | -- | 104,000 | 3,266,640 | ||||||||||||||||||
|
William
Ordemann
|
Various
(1)
|
-- | -- | -- | -- | 86,100 | 2,704,401 | ||||||||||||||||||
|
Michael
J. Knesek
|
Various
(1)
|
-- | -- | -- | -- | 36,300 | 1,140,183 | ||||||||||||||||||
|
Unit
option awards:
|
|||||||||||||||||||||||||
|
Richard
H. Bachmann:
|
|||||||||||||||||||||||||
|
August
4, 2005 option grant
|
8/04/09
|
35,000 | -- | $ | 26.47 |
8/04/15
|
-- | -- | |||||||||||||||||
|
May
1, 2006 option grant
|
5/01/10
|
-- | 40,000 | 24.85 |
5/01/16
|
-- | -- | ||||||||||||||||||
|
May
29, 2007 option grant
|
5/29/11
|
-- | 60,000 | 30.96 |
12/31/12
|
-- | -- | ||||||||||||||||||
|
May
22, 2008 option grant
|
5/22/12
|
-- | 60,000 | 30.93 |
12/31/13
|
-- | -- | ||||||||||||||||||
|
February
19, 2009 option grant
|
2/19/13
|
-- | 60,000 | 22.06 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
May
6, 2009 option grant
|
5/6/13
|
-- | 60,000 | 24.92 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
W.
Randall Fowler (CFO):
|
|||||||||||||||||||||||||
|
August
4, 2005 option grant
|
8/04/09
|
25,000 | -- | 26.47 |
8/04/15
|
-- | -- | ||||||||||||||||||
|
May
1, 2006 option grant
|
5/01/10
|
-- | 40,000 | 24.85 |
5/01/16
|
-- | -- | ||||||||||||||||||
|
May
29, 2007 option grant
|
5/29/11
|
-- | 45,000 | 30.96 |
12/31/12
|
-- | -- | ||||||||||||||||||
|
May
22, 2008 option grant
|
5/22/12
|
-- | 60,000 | 30.93 |
12/31/13
|
-- | -- | ||||||||||||||||||
|
February
19, 2009 option grant
|
2/19/13
|
-- | 52,500 | 22.06 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
May
6, 2009 option grant
|
5/6/13
|
-- | 60,000 | 24.92 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
A.
James Teague:
|
|||||||||||||||||||||||||
|
August
4, 2005 option grant
|
8/04/09
|
35,000 | -- | 26.47 |
8/04/15
|
-- | -- | ||||||||||||||||||
|
May
1, 2006 option grant
|
5/01/10
|
-- | 40,000 | 24.85 |
5/01/16
|
-- | -- | ||||||||||||||||||
|
May
29, 2007 option grant
|
5/29/11
|
-- | 60,000 | 30.96 |
12/31/12
|
-- | -- | ||||||||||||||||||
|
May
22, 2008 option grant
|
5/22/12
|
-- | 60,000 | 30.93 |
12/31/13
|
-- | -- | ||||||||||||||||||
|
February
19, 2009 option grant
|
2/19/13
|
-- | 60,000 | 22.06 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
May
6, 2009 option grant
|
5/6/13
|
-- | 60,000 | 24.92 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
William
Ordemann:
|
|||||||||||||||||||||||||
|
May
10, 2004 option grant
|
5/10/08
|
25,000 | -- | 20.00 |
5/10/14
|
-- | -- | ||||||||||||||||||
|
August
4, 2005 option grant
|
8/04/09
|
25,000 | -- | 26.47 |
8/04/15
|
-- | -- | ||||||||||||||||||
|
May
1, 2006 option grant
|
5/01/10
|
-- | 30,000 | 24.85 |
5/01/16
|
-- | -- | ||||||||||||||||||
|
May
29, 2007 option grant
|
5/29/11
|
-- | 30,000 | 30.96 |
12/31/12
|
-- | -- | ||||||||||||||||||
|
May
22, 2008 option grant
|
5/22/12
|
-- | 60,000 | 30.93 |
12/31/13
|
-- | -- | ||||||||||||||||||
|
February
19, 2009 option grant
|
2/19/13
|
-- | 45,000 | 22.06 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
May
6, 2009 option grant
|
5/6/13
|
-- | 60,000 | 24.92 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
Michael
J. Knesek:
|
|||||||||||||||||||||||||
|
August
4, 2005 option grant
|
8/04/09
|
15,000 | -- | 26.47 |
8/04/15
|
-- | -- | ||||||||||||||||||
|
May
1, 2006 option grant
|
5/01/10
|
-- | 30,000 | 24.85 |
5/01/16
|
-- | -- | ||||||||||||||||||
|
May
29, 2007 option grant
|
5/29/11
|
-- | 30,000 | 30.96 |
12/31/12
|
-- | -- | ||||||||||||||||||
|
May
22, 2008 option grant
|
5/22/12
|
-- | 30,000 | 30.93 |
12/31/13
|
-- | -- | ||||||||||||||||||
|
February
19, 2009 option grant
|
2/19/13
|
-- | 30,000 | 22.06 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
May
6, 2009 option grant
|
5/6/13
|
-- | 30,000 | 24.92 |
12/31/14
|
-- | -- | ||||||||||||||||||
|
(1)
Of
the 421,500 restricted unit awards presented in the table, 50,400 vest in
2010, 98,800 vest in 2011, 121,000 vest in 2012 and 151,300 vest in
2013.
(2)
Amounts
represent the total number of restricted unit awards granted to each named
executive officer.
(3)
Amounts
derived by multiplying the total number of restricted unit awards
outstanding for each named executive officer by the closing price of
Enterprise Products Partners’ common units at December 31, 2009 of $31.41
per unit.
|
|||||||||||||||||||||||||
The following table presents
information concerning each named executive officer’s nonvested profits interest
awards at December 31, 2009:
|
Option
Awards
|
Unit
Awards
|
||||||||||||||||||||
|
Number
of
|
Market
|
||||||||||||||||||||
|
Units
|
Number
|
Value
|
|||||||||||||||||||
|
Underlying
|
Option
|
of
Units
|
of
Units
|
||||||||||||||||||
|
Options
|
Exercise
|
Option
|
That
Have
|
That
Have
|
|||||||||||||||||
|
Vesting
|
Unexercisable
|
Price
|
Expiration
|
Not
Vested
|
Not
Vested
|
||||||||||||||||
|
Name
|
Date (1)
|
(#) |
($/Unit)
|
Date
|
(#) |
($)
|
|||||||||||||||
|
EPE
Unit I:
|
|||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
8/23/10
|
-- | -- | -- | -- | $ | 1,651,767 | ||||||||||||||
|
W.
Randall Fowler (CFO)
|
8/23/10
|
-- | -- | -- | -- | 1,109,396 | |||||||||||||||
|
A.
James Teague
|
8/23/10
|
-- | -- | -- | -- | 1,109,396 | |||||||||||||||
|
William
Ordemann
|
8/23/10
|
-- | -- | -- | -- | 554,698 | |||||||||||||||
|
Michael
J. Knesek
|
8/23/10
|
-- | -- | -- | -- | 554,698 | |||||||||||||||
|
Enterprise
Unit:
|
|||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
2/20/14
|
-- | -- | -- | -- | 654,863 | |||||||||||||||
|
W.
Randall Fowler (CFO)
|
2/20/14
|
-- | -- | -- | -- | 523,890 | |||||||||||||||
|
A.
James Teague
|
2/20/14
|
-- | -- | -- | -- | 654,863 | |||||||||||||||
|
William
Ordemann
|
2/20/14
|
-- | -- | -- | -- | 523,890 | |||||||||||||||
|
Michael
J. Knesek
|
2/20/14
|
-- | -- | -- | -- | 327,431 | |||||||||||||||
|
EPCO
Unit:
|
|||||||||||||||||||||
|
Richard
H. Bachmann (CEO)
|
11/13/13
|
-- | -- | -- | -- | 47,506 | |||||||||||||||
|
W.
Randall Fowler (CFO)
|
11/13/13
|
-- | -- | -- | -- | 47,506 | |||||||||||||||
|
A.
James Teague
|
11/13/13
|
-- | -- | -- | -- | 47,506 | |||||||||||||||
|
(1)
In December 2009, the partnership agreements of each Employee
Partnership were amended to provide that the expected liquidation date for
each Employee Partnership be extended to February 2016. The
extensions of the expected liquidation dates are intended to align the
interests of the employee partners of each Employee Partnership with the
long-term interests of EPCO and other unitholders by providing an
incentive to such employees to devote themselves to maximizing the value
of the underlying publicly traded partnerships over an extended period of
time.
|
|||||||||||||||||||||
The profits interest awards of the
remaining Employee Partnerships had no market (or assumed liquidation) value at
December 31, 2009 due to a decrease in the market value of the limited partner
interests owned by each Employee Partnership since formation.
Option
Exercises and Units Vested
The following table presents the
exercise of unit options by and vesting of restricted units (in each
case, including common units of Enterprise Products Partners, not
Duncan Energy Partners) to our named executive officers during the year ended
December 31, 2009 for which we were historically responsible for a share of the
related expense of such awards.
|
Option
Awards
|
Unit
Awards
|
|||||||||||||||
|
Number
of
|
Gross
|
Number
of
|
Gross
|
|||||||||||||
|
Units
|
Value
|
Units
|
Value
|
|||||||||||||
|
Acquired
on
|
Realized
on
|
Acquired
on
|
Realized
on
|
|||||||||||||
|
Exercise
|
Exercise
|
Vesting
|
Vesting
|
|||||||||||||
|
Name
|
(#) |
($) (1)
|
(#) |
($) (2)
|
||||||||||||
|
Richard
H. Bachmann (CEO)
|
35,000 | $ | 330,400 | 10,000 | $ | 280,500 | ||||||||||
|
W.
Randall Fowler (CFO)
|
10,000 | 93,200 | 6,000 | 168,300 | ||||||||||||
|
A.
James Teague
|
35,000 | 326,200 | 10,000 | 280,500 | ||||||||||||
|
William
Ordemann
|
-- | -- | 16,000 | 451,900 | ||||||||||||
|
Michael
J. Knesek
|
10,000 | 93,200 | 5,000 | 140,250 | ||||||||||||
|
(1)
Amount
determined by multiplying the number of units acquired on exercise of the
options by the difference between the closing price of Enterprise Products
Partners’ common units on the date of exercise less the exercise
price.
(2)
Amount
determined by multiplying the number of restricted unit awards that vested
during 2009 by the closing price of Enterprise Products Partners’ common
units on the date of vesting.
|
||||||||||||||||
Compensation
Committee Report
We do not have a separate compensation
committee. In addition, we do not directly employ or compensate our named
executive officers. Rather, under the ASA, we reimburse EPCO for the
compensation of our executive officers. Accordingly, to the extent
that decisions are made regarding the compensation policies pursuant to which
our named executive officers are compensated, they are made by Mr. Duncan and
EPCO alone (except for equity awards, as previously noted), and not by our
Board.
In light of the foregoing, the Board
has reviewed and discussed with management the Compensation Discussion and
Analysis set forth above and determined that it be included in this annual
report for the year ended December 31, 2009,
Submitted
by: Dan L. Duncan
Richard H. Bachmann
W. Randall Fowler
A. James Teague
Michael A. Creel
Dr. Ralph S. Cunningham
William A. Bruckmann, III
Larry J. Casey
Joe D. Havens
Richard S. Snell
Notwithstanding anything to the
contrary set forth in any previous filings under the Securities Act, as amended,
or the Exchange Act, as amended, that incorporate future filings, including this
annual report, in whole or in part, the foregoing Compensation Committee Report
shall not be incorporated by reference into any such filings.
Compensation
Committee Interlocks and Insider Participation
None of the directors or executive
officers of our general partner served as members of the compensation committee
of another entity that has or had an executive officer who served as a member of
our Board during 2009. As previously noted, we do not have a separate
compensation committee. Mr. Duncan and EPCO alone make compensation
policies (except for equity awards, as previously noted), and not our
Board.
Director
Compensation
Neither we nor DEP GP provide any
additional compensation to employees of EPCO who serve as directors of DEP GP.
The following table presents information regarding compensation to the
independent directors of our general partner, Messrs. Bruckmann, Havens and
Casey, during the year ended December 31, 2009. Mr. Snell was elected as a
director of our general partner effective January 1, 2010 and therefore did not
receive any compensation for service on the Board in 2009.
|
Fees
Earned
|
||||
|
or
Paid
|
||||
|
in
Cash
|
||||
|
Name
|
($)
|
|||
|
William
A. Bruckmann, III
|
$ | 90,000 | ||
|
Joe
D. Havens
|
$ | 75,000 | ||
|
Larry
J. Casey
|
$ | 75,000 | ||
For
2009, the independent directors were compensated for their services as follows:
(i) each received a $75,000 cash retainer annually and (ii) if the individual
served as chairman of a committee of the Board, then he received an additional
$15,000 in cash annually. Effective January 1, 2010, the annual compensation
arrangements for our independent directors changed to the
following:
|
§
|
Each
independent director will receive $75,000 in cash
annually;
|
|
§
|
If
the individual serves as chairman of a committee of the Board of
Directors, then he will receive an additional $15,000 in cash
annually;
|
|
§
|
Each
independent director will receive a meeting fee of $1,500 in cash for each
meeting of the Board attended. In addition, each independent director will
receive a meeting fee of $1,500 in cash for each meeting of a duly
appointed committee of the Board attended, provided that he is duly
elected or appointed to the committee;
and
|
|
§
|
Each
independent director shall receive an annual grant of our common units
having a fair market value, based on the closing price of our common units
on the trading day immediately preceding the date of grant, of
$40,000.
|
Unitholder
Matters.
Security
Ownership of Certain Beneficial Owners
The following table sets forth certain
information as of February 1, 2010, regarding each person known by our general
partner to beneficially own more than 5% of our common units.
|
Amount
and
|
|||||||||
|
Nature
of
|
|||||||||
|
Title
of
|
Name
and Address
|
Beneficial
|
Percent
|
||||||
|
Class
|
of
Beneficial Owner
|
Ownership
|
of
Class
|
||||||
|
Common
units
|
Dan
L. Duncan
|
34,368,640 (1) | 59.6% | ||||||
|
1100
Louisiana Street, 10th
Floor
|
|||||||||
|
Houston,
Texas 77002
|
|||||||||
|
(1)
For
a detailed listing of ownership amounts that comprise Mr. Duncan’s total
beneficial ownership of our common units, see the table presented in the
following section, “Security Ownership of Management,” within this Item
12.
|
|||||||||
Security
Ownership of Management
The following table sets forth certain
information regarding the beneficial ownership of our common units and the
common units of Enterprise Products Partners as of February 1, 2010 by (i) our
named executive officers; (ii) the current directors of DEP GP; and (iii) the
current directors and executive officers of DEP GP as a group. As of
February 1, 2010, Enterprise Products Partners owns 100% of the member interests
of EPO, which directly owns 100% of the member interests of DEP GP and
indirectly owns 58.6% of our common units through a subsidiary. EPO
also retains varying ownership interests in the DEP I and DEP II Midstream
Businesses.
All beneficial ownership information
has been furnished by the respective directors or officers. Each
person has sole voting and dispositive power over the securities shown unless
indicated otherwise. The beneficial ownership amounts of certain
individuals include options to acquire common units of Enterprise Products
Partners that are exercisable within 60 days of the filing date of this annual
report.
Mr. Duncan owns 50.4% of the voting
stock of EPCO and, accordingly, exercises sole voting and dispositive power with
respect to the common units of Enterprise Products Partners that are
beneficially owned by EPCO and its affiliates. The remaining shares
of EPCO capital stock are owned primarily by
trusts
for the benefit of Mr. Duncan’s family. The address of EPCO is 1100
Louisiana Street, 10th
Floor, Houston, Texas 77002.
|
Duncan
Energy Partners L.P.
Common
Units
|
Enterprise
Products Partners L.P.
Common
Units
|
|||||||||||||||
|
Amount
and
|
Amount
and
|
|||||||||||||||
|
Nature
Of
|
Nature
Of
|
|||||||||||||||
|
Beneficial
|
Percent
of
|
Beneficial
|
Percent
of
|
|||||||||||||
|
Name
of Beneficial Owner
|
Ownership
|
Class
|
Ownership
|
Class
|
||||||||||||
|
Dan
L. Duncan:
|
||||||||||||||||
|
Units
owned by EPCO:
|
||||||||||||||||
|
Through
DFI Delaware Holdings, L.P.
|
-- | -- | 130,506,142 | 21.5% | ||||||||||||
|
Through
Duncan Family Interests, Inc.
|
-- | -- | 6,775,839 | 1.1% | ||||||||||||
|
Through
DFI GP Holdings L.P.
|
-- | -- | 3,100,000 | * | ||||||||||||
|
Through
Enterprise GP Holdings L.P.
|
-- | -- | 21,167,783 | 3.5% | ||||||||||||
|
Through
EPCO Holdings, Inc.
|
99,453 | * | 6,182,354 | 1.0% | ||||||||||||
|
Units
owned by EPO
|
33,783,587 | 58.6% | -- | -- | ||||||||||||
|
Units
owned by DD Securities LLC
|
103,100 | * | 1,392,686 | * | ||||||||||||
|
Units
owned by Employee Partnerships (1)
|
-- | -- | 1,623,654 | * | ||||||||||||
|
Units
owned by family trusts (2)
|
-- | -- | 14,624,718 | 2.4% | ||||||||||||
|
Units
owned personally
|
382,500 | * | 1,470,006 | * | ||||||||||||
|
Total
for Dan L. Duncan
|
34,368,640 | 59.6% | 186,843,182 | 30.8% | ||||||||||||
|
Richard
H. Bachmann (CEO) (3,4)
|
14,172 | * | 233,238 | * | ||||||||||||
|
W.
Randall Fowler (CFO) (3,5)
|
2,000 | * | 153,674 | * | ||||||||||||
|
A.
James Teague (3,6)
|
6,000 | * | 295,228 | * | ||||||||||||
|
Michael
A. Creel (7)
|
7,500 | * | 248,868 | * | ||||||||||||
|
Dr.
Ralph S. Cunningham
|
3,000 | * | 104,739 | * | ||||||||||||
|
Larry
J. Casey
|
10,900 | * | 6,600 | * | ||||||||||||
|
Joe
D. Havens
|
11,664 | * | 232,723 | * | ||||||||||||
|
William
A. Bruckmann, III
|
4,500 | * | 4,800 | * | ||||||||||||
|
Richard
S. Snell
|
1,000 | * | 2,064 | * | ||||||||||||
|
William
Ordemann (3)
|
3,810 | * | 117,119 | * | ||||||||||||
|
Michael
J. Knesek (3,8)
|
1,340 | * | 67,853 | * | ||||||||||||
|
All
current directors and executive officers
of
DEP GP, as a group (13 individuals in total) (9)
|
34,436,726 | 59.7% | 188,330,298 | 31.1% | ||||||||||||
|
*
Represents a beneficial ownership of less than 1% of class
|
||||||||||||||||
|
(1)
As
a result of EPCO’s ownership of the general partners of the Employee
Partnerships, Mr. Duncan is deemed beneficial owner of the limited partner
interests held by these entities.
(2)
Mr.
Duncan is deemed beneficial owner of the limited partner interests held by
certain family trusts, the beneficiaries of which are shareholders of
EPCO.
(3)
These
individuals are named executive officers.
(4)
The
number of Enterprise Products Partners’ common units presented for Mr.
Bachmann includes 35,000 common unit options that are exercisable within
60 days of the filing date of this report.
(5)
The
number of Enterprise Products Partners’ common units presented for Mr.
Fowler includes 25,000 common unit options that are exercisable within 60
days of the filing date of this report.
(6)
The
number of Enterprise Products Partners’ common units presented for Mr.
Teague includes 35,000 common unit options that are exercisable within 60
days of the filing date of this report.
(7)
The
number of Enterprise Products Partners’ common units presented for Mr.
Creel includes 35,000 common unit options that are exercisable within 60
days of the filing date of this report.
(8)
The
number of Enterprise Products Partners’ common units presented for Mr.
Knesek includes 709 common units held by a family member for which he has
disclaimed beneficial ownership and 15,000 common unit options that are
exercisable within 60 days of the filing date of this report.
(9)
Cumulatively,
this group’s beneficial ownership amount includes 145,000 options to
acquire Enterprise Products Partners common units that were issued under
the 1998 Plan. These options vested in prior periods and remain
exercisable within 60 days of the filing date of this annual
report.
|
||||||||||||||||
Equity
Ownership Guidelines
On December 31, 2009, the ACG Committee
of the Board recommended to the Board, and effective on January 1, 2010, the
Board adopted and approved, new equity ownership guidelines for our general
partner’s directors and executive officers in order to further align their
interests and actions with the interests of our general partner, us and our
unitholders. Under the new guidelines:
|
§
|
each
non-management director of our general partner is required to own our
common units having an aggregate value (as defined in the guidelines) of
three times the dollar amount of such non-management director’s aggregate
annual cash retainer for service on the Board paid for the most recently
completed calendar year; and
|
|
§
|
each
executive officer of our general partner is required to own our common
units having an aggregate value (as defined in the guidelines) of three
times the dollar amount of such executive officer’s aggregate annual base
salary for the most recently completed calendar year; provided, however,
that the value of any units representing limited partnership interests in
Enterprise Products Partners or Enterprise GP Holdings L.P. (each of which
we refer to as an “Affiliated MLP”), owned by an executive officer of our
general partner who is also an executive officer of the general partner of
such Affiliated MLP, shall be counted toward the equity ownership
requirements set forth above.
|
Securities
Authorized for Issuance Under Equity Compensation Plans
Duncan Energy Partners did not have any
securities authorized for issuance under any effective equity compensation plans
as of December 31, 2009. For information regarding the newly adopted
2010 Plan and EUPP, each of which became effective on February 11, 2010, see
Item 9B of this annual report.
Certain
Relationships and Related Party Transactions
We
believe that the terms and provisions of our related party agreements are fair
to us; however, such agreements and transactions may not be as favorable to us
as we could have obtained from unaffiliated third parties. Additional
information regarding our related party transactions is set forth in Note 15 of
the Notes to Consolidated Financial Statements included under Item 8 of this
annual report and incorporated into this Item 13.
Review and
Approval of Transactions with Related Parties
We generally consider transactions
between us and our subsidiaries, on the one hand, and our executive officers and
directors (or their immediate family members), our general partner or its
affiliates (including companies owned or controlled by Mr. Duncan such as EPCO),
on the other hand, to be related party transactions. As further
described below, our Partnership Agreement sets forth procedures by which
related party transactions and conflicts of interest may be approved or resolved
by the general partner or the ACG Committee. In addition, our ACG
Committee Charter, our general partner’s written internal review and approval
policies and procedures, or “management authorization policy,” and the ASA with
EPCO govern specified related party transactions, as further described
below.
The ACG Committee Charter provides that
the ACG Committee is established to review and approve related party
transactions:
|
§
|
for
which Board approval is required by our management authorization policy,
as such policy may be amended from time to
time;
|
|
§
|
where
an officer or director of the general partner or any of our subsidiaries
is a party, without regard to the size of the
transaction;
|
|
§
|
when
requested to do so by management or the Board;
or
|
|
§
|
pursuant
to our partnership agreement or the limited liability company agreement of
the general partner, as such agreements may be amended from time to
time.
|
As discussed in more detail in “Item
10. Directors, Executive Officers and Corporate Governance
—Partnership Management”, “ – Corporate Governance” and “ – ACG Committee” of
this annual report, at December 31, 2009, the ACG Committee was comprised of
three directors: William A Bruckmann, Joe D. Havens and Larry J.
Casey. Mr. Richard S. Snell was elected as a director in January 2010
and also serves on the ACG Committee. During the year ended December
31, 2009, the ACG Committee reviewed and approved our June 2009 repurchase from
EPO of a total of 8,943,400 of our common units in connection with the
transactions described in Item 5 of this annual report under the heading “Issuer
Purchases of Equity Securities.”
Our management authorization policy
currently requires board approval for the following types of transactions to the
extent such transactions have a value in excess of $100 million (thus triggering
ACG Committee review under our ACG Committee Charter if such transaction is also
a related party transaction):
|
§
|
asset
purchase or sale transactions;
|
|
§
|
capital
expenditures; and
|
|
§
|
purchase
orders and operating and administrative expenses not governed by the
ASA.
|
The ASA
governs numerous day-to-day transactions between us and our subsidiaries, our
general partner and EPCO and its affiliates, including the provision by EPCO of
administrative and other services to us and our subsidiaries and our
reimbursement of costs, without markup or discount, for those
services.
The ACG
Committee reviewed and recommended the ASA, and the Board approved it upon
receiving such recommendation. For a summary of the ASA, see Note 15
of the Notes to Consolidated Financial Statements included under Item 8 of this
annual report.
Related
party transactions that do not occur under the ASA and that are not reviewed by
the ACG Committee, as described above, are subject to the management
authorization policy. This policy, which applies to related party transactions
as well as transactions with unrelated parties, specifies thresholds for our
general partner’s officers and chairman of the Board to authorize various
categories of transactions, including purchases and sales of assets,
expenditures, commercial and financial transactions and legal
agreements.
Business
Opportunity Agreements
The ASA
also addresses potential conflicts that may arise among Enterprise Products
Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings),
Duncan Energy Partners (including DEP GP), and the EPCO Group. The
EPCO Group includes EPCO and its other affiliates, but excludes Enterprise
Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their
respective general partners. With respect to potential conflicts, the
ASA provides, among other things, that:
|
§
|
If
a business opportunity to acquire “equity securities” (as defined
below) is
presented to the EPCO Group, or to Enterprise Products Partners (including
EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy
Partners (including DEP GP), then Enterprise GP Holdings will have the
first right to pursue such opportunity. The term “equity
securities” is defined to
include:
|
|
§
|
general
partner interests (or securities which have characteristics similar to
general partner interests) or interests in “persons” that own or control
such general partner or similar interests (collectively, “GP Interests”)
and securities convertible, exercisable, exchangeable or otherwise
representing ownership or control of such GP Interests;
and
|
|
§
|
incentive
distribution rights and limited partner interests (or securities which
have characteristics similar to incentive distribution rights or limited
partner interests) in publicly traded partnerships or interests in
“persons” that own or control such limited partner or similar interests
(collectively, “non-GP Interests”); provided that such non-GP Interests
are associated with GP Interests and are owned by the owners of GP
Interests or their respective
affiliates.
|
|
|
Enterprise
GP Holdings will be presumed to want to acquire the equity securities
until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP
that it has abandoned the pursuit of such business
opportunity. In the event that the purchase price of the equity
securities is reasonably likely to equal or exceed $100 million, the
decision to decline the acquisition will be made by the chief executive
officer of EPE Holdings after consultation with and subject to the
approval of the ACG Committee of EPE Holdings. If the purchase
price is reasonably likely to be less than $100 million, the chief
executive officer of EPE Holdings may make the determination to decline
the acquisition without consulting the ACG Committee of EPE
Holdings.
|
|
|
In
the event that Enterprise GP Holdings abandons the acquisition and so
notifies the EPCO Group, and EPGP and DEP GP, then Enterprise Products
Partners will have the second right to pursue such
acquisition. Enterprise Products Partners will be presumed to
want to acquire the equity securities until such time as EPGP advises the
EPCO Group and DEP GP that Enterprise Products Partners has abandoned the
pursuit of such acquisition. In determining whether or not to
pursue the acquisition, Enterprise Products Partners will follow the same
procedures applicable to Enterprise GP Holdings, as described above but
utilizing EPGP’s Chief Executive Officer and ACG
Committee.
|
|
|
In
its sole discretion, Enterprise Products Partners may affirmatively direct
such acquisition opportunity to Duncan Energy Partners. In the
event this occurs, Duncan Energy Partners may pursue such
acquisition.
|
|
|
In
the event Enterprise Products Partners abandons the acquisition
opportunity for the equity securities and so notifies the EPCO Group and
DEP GP, the EPCO Group may pursue the acquisition without any further
obligation to any other party or offer such opportunity to other
affiliates.
|
|
§
|
If
any business opportunity not covered by the preceding bullet point (i.e.,
not involving “equity securities”) is presented to the EPCO Group, or to
Enterprise Products Partners (including EPGP), Enterprise GP Holdings
(including EPE Holdings), or Duncan Energy Partners (including DEP GP),
Enterprise Products Partners will have the first right to pursue such
opportunity either for itself or, if desired by Enterprise Products
Partners in its sole discretion, for the benefit of Duncan Energy
Partners. It will be presumed that Enterprise Products Partners
will pursue the business opportunity until such time as its general
partner advises the EPCO Group, EPE Holdings and DEP GP that it has
abandoned the pursuit of such business
opportunity.
|
|
|
In
the event the purchase price or cost associated with the business
opportunity is reasonably likely to equal or exceed $100 million, any
decision to decline the business opportunity will be made by the chief
executive officer of EPGP after consultation with and subject to the
approval of the ACG Committee of EPGP. If the purchase price or
cost is reasonably likely to be less than $100 million, the chief
executive officer of EPGP may make the determination to decline the
business opportunity without consulting EPGP’s ACG
Committee.
|
|
|
In
its sole discretion, Enterprise Products Partners may affirmatively direct
such acquisition opportunity to Duncan Energy
Partners. In
the event this occurs, Duncan Energy Partners may pursue such
acquisition.
|
|
|
In
the event that Enterprise Products Partners abandons the business
opportunity for itself and Duncan Energy Partners and so notifies the EPCO
Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the
second right to pursue such business opportunity. It will be
presumed that Enterprise GP Holdings will pursue such acquisition until
such time as its general partner declines such opportunity (in accordance
with the procedures described above for Enterprise Products Partners) and
advises the EPCO Group that it has abandoned the pursuit of such business
opportunity. Should this occur, the EPCO Group may pursue the
business opportunity without any further obligation to any other party or
offer such opportunity to other
affiliates.
|
Partnership
Agreement Standards for ACG Committee Review
Under our partnership agreement, unless
otherwise expressly provided therein or in the limited liability company (“LLC”)
agreement of EPO, whenever a potential conflict of interest exists or arises
between our general partner or any of its affiliates, on the one hand, and us,
any of our subsidiaries or any partner, on the other hand, any resolution or
course of action by our general partner or its affiliates in respect of such
conflict of interest is permitted and deemed approved by all of our partners,
and will not constitute a breach of our partnership agreement, the LLC agreement
of EPO or any agreement contemplated by such agreements, or of any duty stated
or implied by law or equity, if the resolution or course of action is or, by
operation of the respective agreements is deemed to be, fair and reasonable to
us; provided that, any conflict of interest and any resolution of such conflict
of interest will be conclusively deemed fair and reasonable to us if such
conflict of interest or resolution is (i) approved by a majority of the
members of our general partner’s ACG Committee (i.e., a “Special Approval”) or
(ii) on terms objectively demonstrable to be no less favorable to us than
those generally being provided to or available from third parties.
The ACG Committee (in connection with
Special Approval) is authorized in connection with its resolution of any
conflict of interest to consider:
|
§
|
the
relative interests of any party to such conflict, agreement, transaction
or situation and the benefits and burdens relating to such
interest;
|
|
§
|
the
totality of the relationships between the parties involved (including
other transactions that may be particularly favorable or advantageous to
us);
|
|
§
|
any
customary or accepted industry practices and any customary or historical
dealings with a particular person;
|
|
§
|
any
applicable generally accepted accounting or engineering practices or
principles;
|
|
§
|
the
relative cost of capital of the parties and the consequent rates of return
to the equity holders of the parties;
and
|
|
§
|
such
additional factors as the ACG Committee determines in its sole discretion
to be relevant, reasonable or appropriate under the
circumstances.
|
The
review and approval process of the ACG Committee, including factual matters that
may be considered in determining whether a transaction is fair and reasonable to
us, is generally governed by Section 7.9 of our partnership
agreement. As discussed above, the ACG Committee’s Special Approval
is conclusively deemed fair and reasonable to us under our partnership
agreement.
The
review and work performed by the ACG Committee with respect to a transaction
varies depending upon the nature of the transaction and the scope of the ACG
Committee’s charge. Examples of functions the ACG Committee may, as
it deems appropriate, perform in the course of reviewing a transaction include
(but are not limited to):
|
§
|
assessing
the business rationale for the
transaction;
|
|
§
|
reviewing
the terms and conditions of the proposed transaction, including
consideration and financing requirements, if
any;
|
|
§
|
assessing
the effect of the transaction on our earnings and distributable cash flow
per unit, and on our results of operations, financial condition,
properties or prospects;
|
|
§
|
conducting
due diligence, including by interviews and discussions with management and
other representatives and by reviewing transaction materials and findings
of management and other
representatives;
|
|
§
|
considering
the relative advantages and disadvantages of the transactions to the
parties;
|
|
§
|
engaging
third-party financial advisors to provide financial advice and assistance,
including by providing fairness opinions if
requested;
|
|
§
|
engaging
legal advisors; and
|
|
§
|
evaluating
and negotiating the transaction and recommending for approval or approving
the transaction, as the case may
be.
|
Nothing
contained in the partnership agreement requires the ACG Committee to consider
the interests of any person other than the partnership. In the
absence of bad faith by the ACG Committee or our general partner, the
resolution, action or terms so made, taken or provided (including granting
Special Approval) by the ACG Committee or our general partner with respect to
such matter are conclusive and binding on all persons (including all of our
partners) and do not constitute a breach of the partnership agreement, or any
other agreement contemplated thereby, or a breach of any standard of care or
duty imposed in the partnership agreement or under the Delaware Revised Uniform
Limited Partnership Act or any other law, rule or regulation. The
partnership agreement provides that it is presumed that the resolution, action
or terms made, taken or provided by the ACG Committee or our general partner
were not made, taken or provided in bad faith, and in any proceeding brought by
any limited partner or by or on behalf of such limited partner or any other
limited partner or us challenging such resolution, action or terms, the person
bringing or prosecuting such proceeding will have the burden of overcoming such
presumption.
Director
Independence
Messrs. Bruckmann, Casey, Havens and
Snell have been determined to be independent under the applicable NYSE listing
standards and are independent under the rules of the SEC applicable to audit
committees. For a discussion of independence standards applicable to
the Board and factors considered by the Board in making its independence
determinations, please refer to “Corporate Governance – ACG Committee” under
Item 10 of this annual report.
We have
engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu,
and their respective affiliates (collectively, “Deloitte & Touche”) as our
independent registered public accounting firm and principal
accountants. The following table summarizes fees we paid Deloitte
& Touche for independent auditing, tax and related services for each of the
last two fiscal years (dollars in millions):
|
For
The Year Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Audit
Fees (1)
|
$ | 0.9 | $ | 1.0 | ||||
|
Audit-Related
Fees (2)
|
-- | -- | ||||||
|
Tax
Fees (3)
|
-- | 0.2 | ||||||
|
All
Other Fees (4)
|
N/A | N/A | ||||||
|
(1)
Audit
fees represent amounts billed for each of the years presented for
professional services rendered in connection with (i) the audit of our
annual financial statements and internal controls over financial
reporting, (ii) the review of our quarterly financial statements, or (iii)
those services normally provided in connection with statutory and
regulatory filings or engagements including comfort letters, consents and
other services related to SEC matters. This information is presented
as of the latest practicable date for this annual report.
(2)
Audit-related
fees represent amounts we were billed in each of the years presented for
assurance and related services that are reasonably related to the
performance of the annual audit or quarterly reviews. This category
primarily includes services relating to internal control assessments and
accounting-related consulting.
(3)
Tax
fees represent amounts we were billed in each of the years presented for
professional services rendered in connection with tax compliance, tax
advice, and tax planning. This category primarily includes services
relating to the preparation of unitholder annual K-1 statements and
partnership tax planning. In 2008, PricewaterhouseCoopers International
Limited was engaged to perform the majority of tax related
services.
(4)
All
other fees represent amounts we were billed in each of the years presented
for services not classifiable under the other categories listed in the
table above. No such services were rendered by Deloitte & Touche
during the years ended December 31, 2009 and 2008.
|
||||||||
The ACG Committee of our general
partner has approved the use of Deloitte & Touche as our independent
principal accountant. In connection with its oversight
responsibilities, the ACG Committee has adopted a pre-approval policy regarding
any services proposed to be performed by Deloitte & Touche. The
pre-approval policy includes four primary service categories: Audit,
Audit-related, Tax and Other.
In general, as services are required,
management and Deloitte & Touche submit a detailed proposal to the ACG
Committee discussing the reasons for the request, the scope of work to be
performed, and an estimate of the fee to be charged by Deloitte & Touche for
such work. The ACG Committee discusses the request with management
and Deloitte & Touche, and if the work is deemed necessary and appropriate
for Deloitte & Touche to perform, approves the request subject to the fee
amount presented (the initial “pre-approved” fee amount). As part of
these discussions, the ACG Committee must determine whether or not the proposed
services are permitted under the rules and regulations concerning auditor
independence under the Sarbanes-Oxley Act of 2002 as well as rules of the
American Institute of Certified Public Accountants. If at a later
date, it appears that the initial pre-approved fee amount may be insufficient to
complete the work, then management and Deloitte & Touche must present a
request to the ACG Committee to increase the approved amount and the reasons for
the increase.
Under the pre-approval policy,
management cannot act upon its own to authorize an expenditure for services
outside of the pre-approved amounts. On a quarterly basis, the ACG
Committee is provided a schedule showing Deloitte & Touche’s pre-approved
amounts compared to actual fees billed for each of the primary service
categories. The ACG Committee’s pre-approval process helps to ensure
the independence of our principal accountant from management.
In order for Deloitte & Touche to
maintain its independence, we are prohibited from using them to perform general
bookkeeping, management or human resource functions, and any other service
not
permitted
by the Public Company Accounting Oversight Board. The ACG Committee’s
pre-approval policy also precludes Deloitte & Touche from performing any of
these services for us.
|
(a)
|
The
following documents are filed as a part of this annual
report:
|
|
(1)
|
Financial
Statements: See Index to Consolidated Financial Statements on
page F-1 of this annual report for financial statements filed as part of
this annual report.
|
|
(2)
|
Financial
Statement Schedules: All schedules have been omitted because
they are either not applicable, not required or the information called for
therein appears in the consolidated financial statements or notes
thereto.
|
|
(3)
|
Exhibits.
|
|
Exhibit
Number
|
Exhibit*
|
|
3.1
|
Certificate
of Limited Partnership of Duncan Energy Partners L.P. (incorporated by
reference to Exhibit 3.1 to Form S-1 Registration Statement (Reg. No.
333-138371) filed November 2, 2006).
|
|
3.2
|
Amended
and Restated Agreement of Limited Partnership of Duncan Energy Partners
L.P., dated February 5, 2007 (incorporated by reference to Exhibit
3.1 to Form 8-K filed February 5, 2007).
|
|
3.3
|
Amendment
No. 1 to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated December 27, 2007 (incorporated by
reference to Exhibit 3.1 to Form 8-K/A filed January 3,
2008).
|
|
3.4
|
Amendment
No. 2 to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated November 6, 2008 (incorporated by
reference to Exhibit 3.4 to Form 10-Q filed November 10,
2008).
|
|
3.5
|
Third
Amendment to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P., dated December 8, 2008 (incorporated by
reference to Exhibit 3.1 to Form 8-K filed December 8,
2008).
|
|
3.6
|
Fourth
Amendment to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated June 15, 2009 (incorporated by reference
to Exhibit 3.1 to Form 8-K filed June 15, 2009).
|
|
3.7
|
Certificate
of Formation of DEP Holdings, LLC (incorporated by reference to Exhibit
3.3 to Form S-1 Registration Statement (Reg. No. 333-138371) filed
November 2, 2006).
|
|
3.8
|
Second
Amended and Restated Limited Liability Company Agreement of DEP Holdings,
LLC, dated May 3, 2007 (incorporated by reference to Exhibit 3.4 to Form
10-Q filed May 4, 2007).
|
|
3.9
|
First
Amendment to the Second Amended and Restated Limited Liability Company
Agreement of DEP Holdings, LLC dated November 6, 2008 (incorporated by
reference to Exhibit 3.8 to Form 10-Q filed November 10,
2008).
|
|
3.10
|
Certificate
of Formation of DEP OLPGP, LLC (incorporated by reference to Exhibit 3.5
to Form S-1 Registration Statement (Reg. No. 333-138371) filed November 2,
2006).
|
|
3.11
|
Amended
and Restated Limited Liability Company Agreement of DEP OLPGP, LLC, dated
January 19, 2007 (incorporated by reference to Exhibit 3.6 to Amendment
No. 3 to Form S-1 Registration Statement (Reg. No. 333-138371) filed
January 22, 2007).
|
|
3.12
|
Certificate
of Limited Partnership of DEP Operating Partnership, L.P. (incorporated by
reference to Exhibit 3.7 to Form S-1 Registration Statement (Reg. No.
333-138371) filed November 2, 2006).
|
|
3.13
|
Agreement
of Limited Partnership of DEP Operating Partnership, L.P., dated September
29, 2006 (incorporated by reference to Exhibit 3.8 to Amendment No. 1 to
Form S-1 Registration Statement (Reg. No. 333-138371) filed December 15,
2006).
|
|
10.1***
|
Amended
and Restated 2008 Enterprise Products Long-Term Incentive Plan (February
23, 2010) (incorporated by reference to Exhibit 10.7 to Form 8-K
filed by Enterprise Products Partners L.P. on February 26,
2010).
|
|
10.2***
|
Form
of Option Grant Award under the Amended and Restated 2008 Enterprise
Products Long-Term Incentive Plan for awards issued before
February 23, 2010 (incorporated by reference to Exhibit 4.3 to
Form S-8 filed by Enterprise Products Partners L.P. on May 6,
2008).
|
|
10.3***
|
Amendment
to Form of Option Grant Award under the Amended and Restated 2008
Enterprise Products Long-Term Incentive Plan for awards issued before
February 23, 2010 (incorporated by reference to Exhibit 10.8 to Form 8-K
filed by Enterprise Products Partners L.P. on February 26,
2010).
|
|
10.4***
|
Form
of Option Grant Award under the Amended and Restated 2008 Enterprise
Products Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.9 to Form 8-K filed by Enterprise Products Partners
L.P. on February 26, 2010).
|
|
10.5***
|
Form
of Employee Restricted Unit Grant Award under the Amended and Restated
2008 Enterprise Products Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.10 to Form 8-K filed by Enterprise Products
Partners L.P. on February 26, 2010).
|
|
10.6***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the Amended and
Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated
by reference to Exhibit 10.11 to Form 8-K filed by Enterprise Products
Partners L.P. on February 26, 2010).
|
|
10.7***
|
Enterprise
Products 1998 Long-Term Incentive Plan (Amended and Restated as of
February 23, 2010) (incorporated by reference to Exhibit10.1 to Form 8-K
filed by Enterprise Products Partners L.P. on February 26,
2010).
|
|
10.8***
|
Form
of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan for awards issued before May 7, 2008 (incorporated by
reference to Exhibit 10.2 to Form 10-Q filed by Enterprise
Products Partners L.P. on November 8, 2007).
|
|
10.9***
|
Form
of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan for awards issued on or after May 7, 2008 but before
February 23, 2010 (incorporated by reference to Exhibit 10.4 to
Form 10-Q filed by Enterprise Products Partners L.P. on May 12,
2008).
|
|
10.10***
|
Amendment
to Form of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan for awards issued before February 23, 2010 (incorporated by
reference to Exhibit 10.2 to Form 8-K filed by Enterprise
Products Partners L.P. on February 26, 2010).
|
|
10.11***
|
Form
of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.3 to
Form 8-K filed by Enterprise Products Partners L.P. on February 26,
2010).
|
|
10.12***
|
Form
of Restricted Unit Grant Award under the Enterprise Products 1998
Long-Term Incentive Plan for awards issued before February 23, 2010
(incorporated by reference to Exhibit 10.3 to Form 10-Q filed by
Enterprise Products Partners L.P. on November 8, 2007).
|
|
10.13***
|
Amendment
to Form of Restricted Unit Grant Award under the Enterprise Products 1998
Long-Term Incentive Plan for awards issued before February 23, 2010
(incorporated by reference to Exhibit 10.4 to Form 8-K filed by Enterprise
Products Partners L.P. on February 26, 2010).
|
|
10.14***
|
Form
of Employee Restricted Unit Grant Award under the Enterprise Products 1998
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to
Form 8-K filed by Enterprise Products Partners L.P. on February 26,
2010).
|
|
10.15***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the Enterprise
Products 1998 Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.6 to Form 8-K filed by Enterprise Products Partners L.P. on
February 26, 2010).
|
|
10.16***
|
Enterprise
Products Company 2005 EPE Long-Term Incentive Plan (amended and restated
as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to
Form 8-K filed by Enterprise GP Holdings L.P. on February 26,
2010).
|
|
10.17***
|
Form
of Unit Appreciation Right Grant Award (DEP Holding, LLC Directors) under
the Enterprise Products Company 2005 EPE Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.24 to Form 10-K filed April 2,
2007).
|
|
10.18***
|
Form
of Employee Restricted Unit Grant Award under the Enterprise Products
Company 2005
|
|
|
EPE
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to
Form 8-K filed by Enterprise GP Holdings L.P. on February 26,
2010).
|
|
10.19***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the Enterprise
Products Company 2005 EPE Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.4 to Form 8-K filed by Enterprise GP Holdings L.P.
on February 26, 2010).
|
|
10.20***
|
Form
of Phantom Unit Grant Award under the Enterprise Products Company 2005 EPE
Long-Term Incentive Plan (incorporated by reference to Exhibit10.5 to Form
8-K filed by Enterprise GP Holdings L.P. on February 26,
2010).
|
|
10.21***
|
2010
Duncan Energy Partners L.P. Long-Term Incentive Plan (Amended and Restated
as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to
Form 8-K filed February 26, 2010).
|
|
10.22***
|
Form
of Option Award under the 2010 Duncan Energy Partners L.P. Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K
filed February 26, 2010).
|
|
10.23***
|
Form
of Employee Restricted Unit Grant Award under the 2010 Duncan Energy
Partners L.P. Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.3 to Form 8-K filed February 26, 2010).
|
|
10.24***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the 2010 Duncan
Energy Partners L.P. Long-Term Incentive Plan (incorporated by reference
to Exhibit 10.4 to Form 8-K filed February 26, 2010).
|
|
10.25***
|
Agreement
of Limited Partnership of Enterprise Unit L.P. dated February 20,
2008 (incorporated by reference to Exhibit 10.1 to Form 8-K
filed by Enterprise Products Partners L.P. on February 26,
2008).
|
|
10.26***
|
First
Amendment to Agreement of Limited Partnership of Enterprise Unit L.P.
dated December 2, 2009 (incorporated by reference to
Exhibit 10.4 to Form 8-K filed by Enterprise GP Holdings L.P. on
December 8, 2009).
|
|
10.27***
|
Agreement
of Limited Partnership of EPCO Unit L.P. dated November 13, 2008
(incorporated by reference to Exhibit 10.5 to Form 8-K filed by
Enteprise Products Partners L.P. on November 18, 2008).
|
|
10.28***
|
First
Amendment to Agreement of Limited Partnership of EPCO Unit L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.5 to
Form 8-K filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
|
10.29***
|
Agreement
of Limited Partnership of EPE Unit L.P. dated August 23, 2005
(incorporated by reference to Exhibit 10.2 to Form 8-K filed by Enterprise
GP Holdings L.P. on September 1, 2005).
|
|
10.30***
|
First
Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated
August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q
filed August 8, 2007).
|
|
10.31***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated July
1, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by
Enterprise GP Holdings L.P. on July 7, 2008).
|
|
10.32***
|
Third
Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.1 to
Form 8-K filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
|
10.33***
|
Agreement
of Limited Partnership of EPE Unit II, L.P. dated December 5, 2006
(incorporated by reference to Exhibit 10.13 to Form 10-K filed by
Enterprise Product Partners L.P. on February 28, 2007).
|
|
10.34***
|
First
Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated
August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q
filed August 8, 2007).
|
|
10.35***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated
July 1, 2008 (incorporated by reference to Exhibit 10.2 to Form 8-K filed
by Enterprise GP Holdings L.P. on July 7, 2008).
|
|
10.36***
|
Third
Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.2 to
Form 8-K filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
|
10.37***
|
Agreement
of Limited Partnership of EPE Unit III, L.P. dated May 7, 2007
(incorporated by reference to Exhibit 10.6 to Form 8-K filed by
Enterprise GP Holdings L.P. on May 10, 2007).
|
|
10.38***
|
First
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
August 7,
|
|
|
2007
(incorporated by reference to Exhibit 10.5 to Form 10-Q filed August 8,
2007).
|
|
10.39***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
July 1, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K filed
by Enterprise GP Holdings L.P. on July 7, 2008).
|
|
10.40***
|
Third
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.3 to
Form 8-K filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
|
10.41
|
Second
Amended and Restated Limited Liability Company Agreement of Mont Belvieu
Caverns, LLC dated November 1, 2008 (incorporated by reference to Exhibit
10.4 to Form 10-Q filed November 10, 2008).
|
|
10.42
|
Purchase
and Sale Agreement dated as of December 8, 2008 by and among (a)
Enterprise Products Operating LLC and Enterprise GTM Holdings L.P. as
Seller Parties and (b) Duncan Energy Partners L.P., DEP Holdings, LLC, DEP
Operating Partnership, L.P. and DEP OLP GP, LLC as Buyer Parties
(incorporated by reference to Exhibit 10.1 of Form 8-K filed December 8,
2008).
|
|
10.43
|
Contribution,
Conveyance and Assumption Agreement dated as of December 8, 2008 by and
among Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating
Partnership, L.P., Enterprise GTM Holdings L.P. and Enterprise Holding
III, L.L.C. (incorporated by reference to Exhibit 10.2 of Form 8-K filed
December 8, 2008).
|
|
10.44
|
Third
Amended and Restated Agreement of Limited Partnership of Enterprise GC,
L.P. dated December 8, 2008 (incorporated by reference to Exhibit 10.3 of
Form 8-K filed December 8, 2008).
|
|
10.45
|
Fourth
Amended and Restated Agreement of Limited Partnership of Enterprise
Intrastate L.P. dated December 8, 2008 (incorporated by reference to
Exhibit 10.4 of Form 8-K filed December 8, 2008).
|
|
10.46
|
Amended
and Restated Company Agreement of Enterprise Texas Pipeline LLC dated
December 8, 2008 (incorporated by reference to Exhibit 10.5 of Form 8-K
filed December 8, 2008).
|
|
10.47
|
Amended
and Restated Omnibus Agreement dated December 8, 2008 among Enterprise
Products Operating LLC, DEP Holdings, LLC, Duncan Energy Partners L.P.,
DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex
Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC,
Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC, Enterprise
Holding III, LLC, Enterprise Texas Pipeline LLC, Enterprise Intrastate
L.P. and Enterprise GC, LP (incorporated by reference to Exhibit 10.6 of
Form 8-K filed December 8, 2008).
|
|
10.48
|
Unit
Purchase Agreement, dated as of December 8, 2008, by and between Duncan
Energy Partners L.P. and Enterprise Products Operating LLC (incorporated
by reference to Exhibit 10.9 of Form 8-K filed December 8,
2008).
|
|
10.49
|
Fifth
Amended and Restated Administrative Services Agreement dated January 30,
2009 by and among EPCO, Inc., Enterprise GP Holdings L.P., EPE Holdings,
LLC, Enterprise Products Partners L.P., Enterprise Products Operating
L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., DEP
Holdings, LLC, Duncan Energy Partners L.P., DEP Operating Partnership,
L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC,
TE Products Pipeline Company, LLC, TEPPCO Midstream Companies, LLC, TCTM,
L.P. and TEPPCO GP, Inc. (incorporated by reference to Exhibit 10.1 to
Form 8-K filed by Enterprise Products Partners L.P. on February 5,
2009).
|
|
10.50
|
Common
Unit Purchase Agreement, dated June 15, 2009, by and among Enterprise
Products Operating LLC and Enterprise GTM Holdings L.P. as Sellers and
Duncan Energy Partners L.P. as Buyer (incorporated by reference to Exhibit
1.2 to Form 8-K filed June 18, 2009).
|
|
10.51
|
Revolving
Credit Agreement, dated as of January 5, 2007, among Duncan Energy
Partners L.P., as Borrower, the Lenders Party Thereto, Wachovia Bank,
National Association, as Administrative Agent, Issuing Bank and Swingline
Lender, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication
Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as
Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of
Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and
Joint Book Runners (incorporated by reference to Exhibit 10.20 to
Amendment No. 2 to Form S-1
|
|
|
Registration
Statement (Reg. No. 333-138371) filed January 12,
2007).
|
|
10.52
|
First
Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among
Duncan Energy Partners L.P., as Borrower, the Lenders Party
Thereto. Wachovia Bank, National Association, as Administrative
Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication
Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as
Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of
Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and
Joint Book Runners (incorporated by reference to Exhibit 4.2 to Form 10-Q
filed August 8, 2007).
|
|
10.53
|
Term
Loan Agreement, dated as of April 18, 2008, among Duncan Energy Partners
L.P., as Borrower, the Lenders Party Thereto, Wachovia Bank, National
Association, as Administrative Agent, Suntrust Bank and The Bank of Nova
Scotia, as Co-Syndication Agents, Mizuho Corporate Bank, Ltd. and The
Royal Bank of Scotland plc, as Co-Documentation Agents, and Wachovia
Capital Markets, LLC, SunTrust Robinson Humphrey, a division of SunTrust
Capital Markets, Inc. and The Bank of Nova Scotia, as Joint Lead Arrangers
and Joint Book Runners (incorporated by reference to Exhibit 10.7 of Form
8-K filed December 8, 2008).
|
|
10.54
|
First
Amendment to Term Loan Agreement, dated as of July 11, 2008, among Duncan
Energy Partners L.P., as Borrower, the Lenders Party Thereto, Wachovia
Bank, National Association, as Administrative Agent, Suntrust Bank and The
Bank of Nova Scotia, as Co-Syndication Agents, Mizuho Corporate Bank, Ltd.
and The Royal Bank of Scotland plc, as Co-Documentation Agents, and
Wachovia Capital Markets, LLC, SunTrust Robinson Humphrey, a division of
SunTrust Capital Markets, Inc. and The Bank of Nova Scotia, as Joint Lead
Arrangers and Joint Book Runners (incorporated by reference to Exhibit
10.8 of Form 8-K filed December 8, 2008).
|
|
12.1#
|
Computation
of ratio of earnings to fixed charges for each of the five years ended
December 31, 2009, 2008, 2007, 2006 and 2005.
|
|
21.1#
|
List
of Subsidiaries as of February 1, 2010.
|
|
23.1#
|
Consent
of Deloitte & Touche LLP.
|
|
31.1#
|
Sarbanes-Oxley
Section 302 certification of Richard H. Bachmann for Duncan Energy
Partners L.P. for the December 31, 2009 Annual Report on Form
10-K.
|
|
31.2#
|
Sarbanes-Oxley
Section 302 certification of W. Randall Fowler for Duncan Energy Partners
L.P. for the December 31, 2009 Annual Report on Form
10-K.
|
|
32.1#
|
Section
1350 certification of Richard H. Bachmann for the December 31, 2009 Annual
Report on Form 10-K.
|
|
32.2#
|
Section
1350 certification of W. Randall Fowler for the December 31, 2009 Annual
Report on Form 10-K.
|
|
*
|
With
respect to exhibits incorporated by reference to Exchange Act filings, the
Commission file numbers for Enterprise Products Partners L.P. and
Enterprise GP Holdings L.P. are 1-14323 and 1-32610,
respectively.
|
|
***
|
Identifies
management contract and compensatory plan
arrangements.
|
|
#
|
Filed
with this report.
|
Pursuant to the requirements of Section
13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized
on March 1, 2010.
|
DUNCAN
ENERGY PARTNERS L.P.
|
|||||
|
(A
Delaware Limited Partnership)
|
|||||
|
By: DEP
Holdings, LLC, as General Partner
|
|||||
|
By: /s/
Michael J.
Knesek
|
|||||
|
Name: Michael
J. Knesek
|
|||||
|
Title: Senior
Vice President, Controller
and
Principal Accounting Officer
of
the General Partner
|
Pursuant to the requirements of the
Securities Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities indicated below on
March 1, 2010.
|
Signature
|
Title
(Position with DEP Holdings, LLC)
|
|
|
/s/
Dan L. Duncan
|
Director
and Chairman
|
|
|
Dan
L. Duncan
|
||
|
/s/
Richard H. Bachmann
|
Director,
President and Chief Executive Officer
|
|
|
Richard
H. Bachmann
|
||
|
/s/
W. Randall Fowler
|
Director,
Executive Vice President and Chief Financial Officer
|
|
|
W.
Randall Fowler
|
||
|
/s/
A. James Teague
|
Director,
Executive Vice President and Chief Commercial
Officer
|
|
|
A.
James Teague
|
||
|
/s/
Michael A. Creel
|
Director
|
|
|
Michael
A. Creel
|
||
|
/s/
Dr. Ralph S. Cunningham
|
Director
|
|
|
Dr.
Ralph S. Cunningham
|
||
|
/s/
Larry J. Casey
|
Director
|
|
|
Larry
J. Casey
|
||
|
/s/
Joe D. Havens
|
Director
|
|
|
Joe
D. Havens
|
||
|
/s/
William A. Bruckmann, III
|
Director
|
|
|
William
A. Bruckmann, III
|
||
|
/s/
Richard S. Snell
|
Director
|
|
|
Richard
S. Snell
|
||
|
/s/
Michael J. Knesek
|
Senior
Vice President, Controller and Principal Accounting
Officer
|
|
|
Michael
J. Knesek
|
DUNCAN
ENERGY PARTNERS L.P.
INDEX
TO FINANCIAL STATEMENTS
|
Page
No.
|
||
|
|
||
To the
Board of Directors of DEP Holdings, LLC and
Unitholders
of Duncan Energy Partners L.P.
Houston,
Texas
We have audited the accompanying
consolidated balance sheets of Duncan Energy Partners L.P. and subsidiaries (the
"Company") as of December 31, 2009 and 2008, and the related statements of
consolidated operations, comprehensive income, cash flows, and equity for each
of the three years in the period ended December 31, 2009. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on the
financial statements 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, such consolidated
financial statements present fairly, in all material respects, the financial
position of Duncan Energy Partners L.P. and subsidiaries at December 31, 2009
and 2008, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2009, in conformity with
accounting principles generally accepted in the United States of
America.
We have also audited, in accordance
with the standards of the Public Company Accounting Oversight Board (United
States), the Company's internal control over financial reporting as of December
31, 2009, based on the criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated March 1, 2010 expresses an unqualified
opinion on the Company's internal control over financial reporting.
As discussed in Note 1 to the
Consolidated Financial Statements, the accompanying financial statements have
been prepared from the separate records maintained by Enterprise Products
Partners L.P. or affiliates and may not necessarily be indicative of the
conditions that would have existed or the results of operations if the Company
had been operated as an unaffiliated entity.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
March 1,
2010
CONSOLIDATED
BALANCE SHEETS
(Dollars
in millions)
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
assets
|
||||||||
|
Cash
and cash equivalents
|
$ | 3.9 | $ | 13.0 | ||||
|
Accounts
receivable – trade, net of allowance for doubtful accounts
|
77.7 | 117.3 | ||||||
|
Accounts
receivable – related parties
|
54.5 | 3.3 | ||||||
|
Gas
imbalance receivables
|
9.8 | 35.7 | ||||||
|
Inventories
|
10.5 | 28.0 | ||||||
|
Prepaid
and other current assets
|
9.8 | 4.3 | ||||||
|
Total current assets
|
166.2 | 201.6 | ||||||
|
Property,
plant and equipment, net
|
4,549.6 | 4,330.2 | ||||||
|
Investments
in Evangeline
|
5.6 | 4.5 | ||||||
|
Intangible
assets, net of accumulated amortization of $42.6 at December 31,
2009
|
||||||||
|
and
$34.1 at December 31, 2008
|
43.8 | 52.3 | ||||||
|
Goodwill
|
4.9 | 4.9 | ||||||
|
Other
assets
|
0.7 | 1.2 | ||||||
|
Total assets
|
$ | 4,770.8 | $ | 4,594.7 | ||||
|
LIABILITIES
AND EQUITY
|
||||||||
|
Current
liabilities
|
||||||||
|
Accounts
payable – trade
|
$ | 54.5 | $ | 45.2 | ||||
|
Accounts
payable – related parties
|
13.6 | 48.5 | ||||||
|
Accrued
product payables
|
59.9 | 109.7 | ||||||
|
Accrued
property taxes
|
9.1 | 8.3 | ||||||
|
Accrued
taxes – other
|
8.4 | 8.3 | ||||||
|
Other
current liabilities
|
18.9 | 33.3 | ||||||
|
Total current liabilities
|
164.4 | 253.3 | ||||||
|
Long-term debt (see Note
11)
|
457.3 | 484.3 | ||||||
|
Deferred
tax liabilities
|
5.8 | 5.7 | ||||||
|
Other
long-term liabilities
|
6.4 | 7.2 | ||||||
|
Commitments
and contingencies
|
||||||||
|
Equity:
|
||||||||
|
Duncan
Energy Partners L.P. partners’ equity: (see Note 12)
|
||||||||
|
Limited partners
|
||||||||
|
Common units (57,676,987 common units outstanding at December 31, 2009
and
|
||||||||
|
20,343,100 common units outstanding at December 31, 2008)
|
766.6 | 308.2 | ||||||
|
Class B units (37,333,887 Class B units outstanding at December 31,
2008)
|
-- | 453.8 | ||||||
|
General partner
|
0.2 | 0.4 | ||||||
|
Accumulated other comprehensive loss
|
(5.4 | ) | (9.6 | ) | ||||
|
Total Duncan Energy Partners L.P. partners’ equity
|
761.4 | 752.8 | ||||||
|
Noncontrolling
interest in subsidiaries: (see Note 13)
|
||||||||
|
DEP I Midstream Businesses – Parent
|
487.3 | 478.4 | ||||||
|
DEP II Midstream Businesses – Parent
|
2,888.2 | 2,613.0 | ||||||
|
Total noncontrolling interest
|
3,375.5 | 3,091.4 | ||||||
|
Total equity
|
4,136.9 | 3,844.2 | ||||||
|
Total
liabilities and equity
|
$ | 4,770.8 | $ | 4,594.7 | ||||
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF CONSOLIDATED OPERATIONS
(Dollars
in millions)
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Revenues
|
||||||||||||
|
Third
parties
|
$ | 492.0 | $ | 856.4 | $ | 759.3 | ||||||
|
Related
parties
|
487.3 | 741.7 | 461.0 | |||||||||
|
Total revenues (see Note 14)
|
979.3 | 1,598.1 | 1,220.3 | |||||||||
|
Costs
and Expenses
|
||||||||||||
|
Operating
costs and expenses:
|
||||||||||||
|
Third
parties
|
749.0 | 1,167.7 | 1,066.7 | |||||||||
|
Related
parties
|
159.3 | 345.1 | 104.3 | |||||||||
|
Total
operating costs and expenses
|
908.3 | 1,512.8 | 1,171.0 | |||||||||
|
General
and administrative costs:
|
||||||||||||
|
Third
parties
|
0.3 | 3.4 | 1.7 | |||||||||
|
Related
parties
|
10.9 | 14.9 | 11.4 | |||||||||
|
Total
general and administrative costs
|
11.2 | 18.3 | 13.1 | |||||||||
|
Total
costs and expenses
|
919.5 | 1,531.1 | 1,184.1 | |||||||||
|
Equity
in income of Evangeline
|
1.1 | 0.9 | 0.2 | |||||||||
|
Operating
income
|
60.9 | 67.9 | 36.4 | |||||||||
|
Other
income (expense)
|
||||||||||||
|
Interest
expense
|
(14.0 | ) | (12.0 | ) | (9.3 | ) | ||||||
|
Other,
net
|
0.2 | 0.5 | 0.7 | |||||||||
|
Other
expense, net
|
(13.8 | ) | (11.5 | ) | (8.6 | ) | ||||||
|
Income
before provision for income taxes
|
47.1 | 56.4 | 27.8 | |||||||||
|
Provision
for income taxes
|
(1.3 | ) | (1.1 | ) | (4.2 | ) | ||||||
|
Net
income
|
45.8 | 55.3 | 23.6 | |||||||||
|
Net
loss (income) attributable to noncontrolling interest: (see Note
13)
|
||||||||||||
|
DEP
I Midstream Businesses - Parent
|
(15.3 | ) | (11.4 | ) | (20.0 | ) | ||||||
|
DEP
II Midstream Businesses - Parent
|
60.6 | 4.0 | -- | |||||||||
|
Total
net loss (income) attributable to noncontrolling interest
|
45.3 | (7.4 | ) | (20.0 | ) | |||||||
|
Net income attributable to
Duncan Energy Partners L.P. (see Note 1)
|
$ | 91.1 | $ | 47.9 | $ | 3.6 | ||||||
|
Allocation
of net income attributable to Duncan Energy
|
||||||||||||
|
Partners L.P.: (see Note
1)
|
||||||||||||
|
Duncan
Energy Partners L.P.:
|
||||||||||||
|
Limited
partners’ interest in net income
|
$ | 90.5 | $ | 27.8 | $ | 18.8 | ||||||
|
General
partner interest in net income
|
$ | 0.6 | $ | 0.5 | $ | 0.4 | ||||||
|
Former
owners of DEP I Midstream Businesses
|
n/a | $ | 5.0 | |||||||||
|
Former
owners of DEP II Midstream Businesses
|
$ | 19.6 | $ | (20.6 | ) | |||||||
|
Basic and diluted earnings per
unit (see Note 16)
|
$ | 1.57 | $ | 1.22 | $ | 0.93 | ||||||
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF CONSOLIDATED COMPREHENSIVE INCOME
(Dollars
in millions)
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
income
|
$ | 45.8 | $ | 55.3 | $ | 23.6 | ||||||
|
Other
comprehensive income (loss):
|
||||||||||||
|
Cash
flow hedges:
|
||||||||||||
|
Interest
rate derivative instrument losses during period
|
(2.5 | ) | (8.0 | ) | (3.3 | ) | ||||||
|
Reclassification
adjustment for (gains) losses included in net
|
||||||||||||
|
income
related to interest rate derivative instruments
|
6.6 | 2.0 | (0.3 | ) | ||||||||
|
Commodity
derivative instrument losses during period
|
-- | (0.7 | ) | (0.1 | ) | |||||||
|
Reclassification
adjustment for losses included in net
|
||||||||||||
|
income
related to commodity derivative instruments
|
-- | 0.7 | 0.1 | |||||||||
|
Total
other comprehensive income (loss)
|
4.1 | (6.0 | ) | (3.6 | ) | |||||||
|
Comprehensive
income
|
49.9 | 49.3 | 20.0 | |||||||||
|
Comprehensive
loss (income) attributable to noncontrolling interest:
|
||||||||||||
|
DEP
I Midstream Businesses – Parent
|
(15.3 | ) | (11.4 | ) | (20.0 | ) | ||||||
|
DEP
II Midstream Businesses – Parent
|
60.6 | 4.0 | -- | |||||||||
|
Total
comprehensive loss (income) attributable to noncontrolling
interest
|
45.3 | (7.4 | ) | (20.0 | ) | |||||||
|
Comprehensive
loss (income) allocated to former owners of DEP II Midstream
Businesses
|
-- | (19.6 | ) | 20.6 | ||||||||
|
Comprehensive
income attributable to Duncan Energy Partners L.P.
|
$ | 95.2 | $ | 22.3 | $ | 20.6 | ||||||
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF CONSOLIDATED CASH FLOWS
(Dollars
in millions)
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Operating
activities:
|
||||||||||||
|
Net
income
|
$ | 45.8 | $ | 55.3 | $ | 23.6 | ||||||
|
Adjustments
to reconcile net income to net cash flows
|
||||||||||||
|
provided
by operating activities:
|
||||||||||||
|
Depreciation,
amortization and accretion
|
188.3 | 167.8 | 175.6 | |||||||||
|
Equity
in income of Evangeline
|
(1.1 | ) | (0.9 | ) | (0.2 | ) | ||||||
|
Gain
on sale of assets and related transactions
|
(0.5 | ) | (0.5 | ) | (0.1 | ) | ||||||
|
Deferred
income tax expense
|
-- | 0.3 | 3.8 | |||||||||
|
Non-cash
asset impairment
|
4.2 | -- | -- | |||||||||
|
Changes
in fair market value of derivative instruments
|
(0.2 | ) | (0.1 | ) | 0.2 | |||||||
|
Net
effect of changes in operating accounts (see Note 19)
|
(80.5 | ) | (1.8 | ) | 14.2 | |||||||
|
Cash flows provided by operating activities
|
156.0 | 220.1 | 217.1 | |||||||||
|
Investing
activities:
|
||||||||||||
|
Capital
expenditures
|
(389.1 | ) | (759.5 | ) | (340.1 | ) | ||||||
|
Contributions
in aid of construction costs
|
5.7 | 9.9 | 10.0 | |||||||||
|
Proceeds
from sale of assets and related transactions
|
0.9 | 0.9 | 12.6 | |||||||||
|
Cash
used for business combinations
|
(0.7 | ) | -- | (35.0 | ) | |||||||
|
Other
|
-- | (0.1 | ) | 0.1 | ||||||||
|
Cash
used in investing activities
|
(383.2 | ) | (748.8 | ) | (352.4 | ) | ||||||
|
Financing
activities:
|
||||||||||||
|
Repayments
of debt
|
(103.2 | ) | (114.7 | ) | (114.0 | ) | ||||||
|
Borrowings
under debt agreements
|
76.2 | 398.9 | 314.0 | |||||||||
|
Debt
issuance costs
|
(0.4 | ) | (1.6 | ) | (0.5 | ) | ||||||
|
Net
proceeds from Duncan Energy Partners’ common unit
offerings
|
137.4 | 0.5 | 290.5 | |||||||||
|
Common
units repurchased from EPO and subsequently retired
|
(137.4 | ) | -- | -- | ||||||||
|
Cash
distributions to Duncan Energy Partners’ unitholders and general
partner
|
(88.9 | ) | (34.4 | ) | (21.8 | ) | ||||||
|
Cash
distributions to noncontrolling interest
|
(51.6 | ) | (318.1 | ) | (491.0 | ) | ||||||
|
Cash
contributions from noncontrolling interest
|
386.0 | 183.3 | 105.0 | |||||||||
|
Net
cash contributions from former owners of the
|
||||||||||||
|
DEP
I Midstream Businesses
|
-- | -- | 8.5 | |||||||||
|
Net
cash contributions from former owners of the
|
||||||||||||
|
DEP
II Midstream Businesses
|
-- | 425.6 | 46.8 | |||||||||
|
Cash provided by financing activities
|
218.1 | 539.5 | 137.5 | |||||||||
|
Net
changes in cash and cash equivalents
|
(9.1 | ) | 10.8 | 2.2 | ||||||||
|
Cash
and cash equivalents, beginning of period
|
13.0 | 2.2 | -- | |||||||||
|
Cash
and cash equivalents, end of period
|
$ | 3.9 | $ | 13.0 | $ | 2.2 | ||||||
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF CONSOLIDATED EQUITY
(Dollars
in millions)
|
Former
Owners
|
||||||||||||||||||||||||||||
|
DEP
I
|
DEP
II
|
Duncan
Energy Partners
|
Noncontrolling
|
|||||||||||||||||||||||||
|
Midstream
|
Midstream
|
Limited
|
General
|
Interest
in
|
||||||||||||||||||||||||
|
Businesses
|
Businesses
|
Partners
|
Partner
|
AOCI
|
Subsidiaries
|
Total
|
||||||||||||||||||||||
|
Balance,
January 1, 2007
|
$ | 725.8 | $ | 2,853.8 | $ | -- | $ | -- | $ | -- | $ | -- | $ | 3,579.6 | ||||||||||||||
|
Transactions
prior to the DEP I dropdown effective February 1, 2007:
|
||||||||||||||||||||||||||||
|
Net
income (loss)
|
5.0 | (0.3 | ) | -- | -- | -- | -- | 4.7 | ||||||||||||||||||||
|
Net
cash contributions (distributions) to former owners
|
8.5 | (8.8 | ) | -- | -- | -- | -- | (0.3 | ) | |||||||||||||||||||
|
Balance,
January 31, 2007
|
739.3 | 2,844.7 | -- | -- | -- | -- | 3,584.0 | |||||||||||||||||||||
|
Transactions
in connection with Duncan Energy Partners’ initial
public offering
and the DEP I drop down effective February 1, 2007:
|
||||||||||||||||||||||||||||
|
Adjustment
for liabilities of DEP I Midstream Businesses not
transferred
|
||||||||||||||||||||||||||||
|
Adjustment
for liabilities of DEP I Midstream Businesses not transferred
to Duncan Energy Partners
|
2.7 | -- | -- | -- | -- | -- | 2.7 | |||||||||||||||||||||
|
Retention
by noncontrolling interest of ownership interests
|
(252.3 | ) | -- | -- | -- | -- | 252.3 | -- | ||||||||||||||||||||
|
Allocation
of equity in the DEP I Midstream Businesses
|
||||||||||||||||||||||||||||
|
to
Duncan Energy Partners
|
(489.7 | ) | -- | 479.9 | 9.8 | -- | -- | -- | ||||||||||||||||||||
|
Net
proceeds from Duncan Energy Partners’ initial public
offering
|
-- | -- | 290.5 | -- | -- | -- | 290.5 | |||||||||||||||||||||
|
Cash
distribution to noncontrolling interest at time of initial
public offering
|
-- | -- | (450.3 | ) | (9.2 | ) | -- | -- | (459.5 | ) | ||||||||||||||||||
|
Balance,
February 1, 2007
|
$ | -- | 2,844.7 | 320.1 | 0.6 | -- | 252.3 | 3,417.7 | ||||||||||||||||||||
|
Net
income (loss)
|
(20.3 | ) | 18.8 | 0.4 | -- | 20.0 | 18.9 | |||||||||||||||||||||
|
Amortization
of equity awards
|
-- | 0.2 | -- | -- | -- | 0.2 | ||||||||||||||||||||||
|
Cash
contributions from former owners
|
55.6 | -- | -- | -- | -- | 55.6 | ||||||||||||||||||||||
|
Cash
distributions to partners
|
-- | (21.4 | ) | (0.4 | ) | -- | -- | (21.8 | ) | |||||||||||||||||||
|
Cash
contributions from noncontrolling interest
|
-- | -- | -- | -- | 105.0 | 105.0 | ||||||||||||||||||||||
|
Cash
distributions to noncontrolling interest
|
-- | -- | -- | -- | (31.5 | ) | (31.5 | ) | ||||||||||||||||||||
|
Cash
flow hedges
|
-- | -- | -- | (3.6 | ) | -- | (3.6 | ) | ||||||||||||||||||||
|
Other
|
0.1 | -- | -- | -- | 9.4 | 9.5 | ||||||||||||||||||||||
|
Balance,
December 31, 2007
|
2,880.1 | 317.7 | 0.6 | (3.6 | ) | 355.2 | 3,550.0 | |||||||||||||||||||||
|
Transactions
prior to the DEP II drop down on December
8, 2008:
|
||||||||||||||||||||||||||||
|
Net
income – January 1, 2008 through December 7, 2008
|
19.6 | 21.1 | 0.4 | -- | 12.0 | 53.1 | ||||||||||||||||||||||
|
Amortization
of equity awards
|
-- | 0.2 | -- | -- | -- | 0.2 | ||||||||||||||||||||||
|
Cash
contributions from former owner
|
425.6 | -- | -- | -- | -- | 425.6 | ||||||||||||||||||||||
|
Cash
contributions from noncontrolling interest
|
-- | -- | -- | -- | 161.6 | 161.6 | ||||||||||||||||||||||
|
Cash
distributions to noncontrolling interest
|
-- | -- | -- | -- | (37.3 | ) | (37.3 | ) | ||||||||||||||||||||
|
Cash
distributions to partners
|
-- | (33.7 | ) | (0.7 | ) | -- | -- | (34.4 | ) | |||||||||||||||||||
|
Cash
flow hedges
|
-- | -- | -- | (0.3 | ) | -- | (0.3 | ) | ||||||||||||||||||||
|
Other
|
0.2 | -- | -- | -- | (12.5 | ) | (12.3 | ) | ||||||||||||||||||||
|
Balance,
December 7, 2008
|
3,325.5 | 305.3 | 0.3 | (3.9 | ) | 479.0 | 4,106.2 | |||||||||||||||||||||
|
Transactions
in connection with the DEP II drop down on
December 8, 2008:
|
||||||||||||||||||||||||||||
|
Retention
by noncontrolling interest of ownership interests
|
(2,595.5 | ) | -- | -- | -- | 2,595.5 | -- | |||||||||||||||||||||
|
Allocation
of equity in the DEP II Midstream Businesses
|
||||||||||||||||||||||||||||
|
to
Duncan Energy Partners
|
(730.0 | ) | 730.0 | -- | -- | -- | -- | |||||||||||||||||||||
|
Cash
distribution paid to noncontrolling interest at DEP II drop
down
|
-- | (280.5 | ) | -- | -- | -- | (280.5 | ) | ||||||||||||||||||||
|
Net
proceeds from the issuance of common units
|
-- | 0.5 | -- | -- | -- | 0.5 | ||||||||||||||||||||||
|
Balance,
December 8, 2008
|
$ | -- | 755.3 | 0.3 | (3.9 | ) | 3,074.5 | 3,826.2 | ||||||||||||||||||||
|
Net
income (loss) – December 8, 2008 through December 31, 2008
|
6.7 | 0.1 | -- | (4.6 | ) | 2.2 | ||||||||||||||||||||||
|
Cash
contributions from noncontrolling interest
|
-- | -- | -- | 21.7 | 21.7 | |||||||||||||||||||||||
|
Cash
distributions to noncontrolling interest
|
-- | -- | -- | (0.3 | ) | (0.3 | ) | |||||||||||||||||||||
|
Cash
flow hedges
|
-- | -- | (5.7 | ) | -- | (5.7 | ) | |||||||||||||||||||||
|
Other
|
-- | -- | -- | 0.1 | 0.1 | |||||||||||||||||||||||
|
Balance,
December 31, 2008
|
762.0 | 0.4 | (9.6 | ) | 3,091.4 | 3,844.2 | ||||||||||||||||||||||
|
Net
income (loss)
|
90.5 | 0.6 | -- | (45.3 | ) | 45.8 | ||||||||||||||||||||||
|
Amortization
of equity awards
|
2.2 | -- | -- | -- | 2.2 | |||||||||||||||||||||||
|
Net
proceeds from Duncan Energy Partners’ common unit
offerings
|
137.4 | -- | -- | -- | 137.4 | |||||||||||||||||||||||
|
Cash
contributions from noncontrolling interest
|
-- | -- | -- | 386.0 | 386.0 | |||||||||||||||||||||||
|
Cash
distributions to noncontrolling interest
|
-- | -- | -- | (51.6 | ) | (51.6 | ) | |||||||||||||||||||||
|
Cash
distributions to unitholders and general partner
|
(88.1 | ) | (0.8 | ) | -- | -- | (88.9 | ) | ||||||||||||||||||||
|
Common
units repurchased from EPO and retired (see Note 12)
|
(137.4 | ) | -- | -- | -- | (137.4 | ) | |||||||||||||||||||||
|
Cash
flow hedges
|
-- | -- | 4.2 | -- | 4.2 | |||||||||||||||||||||||
|
Other
|
-- | -- | -- | (5.0 | ) | (5.0 | ) | |||||||||||||||||||||
|
Balance,
December 31, 2009
|
$ | 766.6 | $ | 0.2 | $ | (5.4 | ) | $ | 3,375.5 | $ | 4,136.9 | |||||||||||||||||
The
accompanying notes are an integral part of these financial
statements.
SIGNIFICANT
RELATIONSHIPS REFERENCED IN THESE
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Unless the context requires otherwise,
references to “we,” “us,” “our,” or “Duncan Energy Partners” are intended to
mean the business and operations of Duncan Energy Partners L.P. and its
consolidated subsidiaries.References to “DEP GP” mean DEP Holdings, LLC,
which is our general partner. References to “DEP OLP” mean DEP
Operating Partnership, L.P., which is a wholly owned subsidiary of Duncan Energy
Partners through which Duncan Energy Partners conducts substantially all of its
business.
References to “Enterprise Products
Partners” mean the business and operations of Enterprise Products Partners L.P.
and its consolidated subsidiaries. Enterprise Products Partners is a
publicly traded Delaware limited partnership, the common units of which are
listed on the New York Stock Exchange (“NYSE”) under the ticker symbol
“EPD.” References to “EPGP” mean Enterprise
Products GP, LLC, which is the general partner of Enterprise Products
Partners. References to “EPO” mean Enterprise Products Operating LLC,
which is a wholly owned subsidiary of Enterprise Products Partners through which
Enterprise Products Partners conducts substantially all of its business, and its
consolidated subsidiaries. EPO beneficially owns 100% of DEP GP and
is a significant owner of our common units. Enterprise Products
Partners consolidates our financial statements with those of its
own.
References to “TEPPCO” and “TEPPCO GP”
mean TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC
(which is the general partner of TEPPCO), respectively, prior to their mergers
with subsidiaries of Enterprise Products Partners (the “TEPPCO
Merger”). On October 26, 2009, Enterprise Products Partners completed
the mergers with TEPPCO and TEPPCO GP. On October 27, 2009,
Enterprise Products Partners’ TEPPCO and TEPPCO GP equity interests were
contributed to EPO, and TEPPCO and TEPPCO GP became wholly owned subsidiaries of
EPO.
References to “Enterprise
GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded Delaware
limited partnership, the units of which are listed on the NYSE under the ticker
symbol “EPE.” Enterprise GP Holdings owns EPGP. The
general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”),
a wholly owned subsidiary of Dan Duncan LLC, all of the membership interests of
which are owned by Dan L. Duncan.
References to “Energy Transfer Equity”
mean the business and operations of Energy Transfer Equity, L.P. and its
consolidated subsidiaries, which include Energy Transfer Partners, L.P.
(“ETP”). Energy Transfer Equity is a publicly traded Delaware limited
partnership, the common units of which are listed on the NYSE under the ticker
symbol “ETE.” ETP is a publicly traded Delaware limited partnership,
the common units of which are listed on the NYSE under the ticker symbol
“ETP.” The general partner of Energy Transfer Equity is LE GP, LLC
(“LE GP”).
References to the “DEP I Midstream
Businesses” collectively refer to (i) Mont Belvieu Caverns, LLC (“Mont Belvieu
Caverns”); (ii) Acadian Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex
Propylene Pipeline L.P. (“Lou-Tex Propylene”), including its general partner;
(iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), including its general
partner; and (v) South Texas NGL Pipelines, LLC (“South Texas
NGL”). We acquired controlling ownership interests in the DEP I
Midstream Businesses from EPO effective February 1, 2007 in a drop down
transaction (the “DEP I drop down”) in connection with our initial public
offering.
References to the “DEP II Midstream
Businesses” collectively refer to (i) Enterprise GC, L.P. (“Enterprise GC”);
(ii) Enterprise Intrastate L.P. (“Enterprise Intrastate”); and (iii) Enterprise
Texas Pipeline LLC (“Enterprise Texas”). We acquired controlling
ownership interests in the DEP II Midstream Businesses from EPO on December 8,
2008 in a drop down transaction (the “DEP II drop
down”). Our
ownership
interests in the DEP II Midstream Businesses are held by Enterprise Holding III,
L.L.C., which is a wholly owned subsidiary of DEP OLP. Ownership
interests in the DEP II Midstream Businesses that were retained by EPO are held
by its wholly owned subsidiary, Enterprise GTM Holdings L.P.
Within the context of our financial
information, references to “former owners” mean EPO’s ownership interests in the
DEP I and DEP II Midstream Businesses prior to the effective date of the related
drop down transactions.
References to “Evangeline” mean our
aggregate 49.51% equity method investment in Evangeline Gas Pipeline Company,
L.P. (“EGP”) and Evangeline Gas Corp (“EGC”).
References to “EPCO” mean Enterprise
Products Company (formerly EPCO, Inc.) and its privately held
affiliates. We, Enterprise Products Partners, EPO, DEP GP, EPGP,
Enterprise GP Holdings and EPE Holdings are affiliates under the common control
of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of
EPCO.
References to “Employee Partnerships”
mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit
III, L.P. (“EPE Unit III”), Enterprise Unit L.P. (“Enterprise Unit”) and EPCO
Unit L.P. (“EPCO Unit”), collectively, all of which are privately held
affiliates of EPCO.
and Basis of Financial Statement
Presentation
Duncan Energy Partners is a publicly
traded Delaware limited partnership, the common units of which are listed on the
NYSE under the ticker symbol “DEP.” Duncan Energy Partners is engaged
in the business of: (i) natural gas liquids (“NGLs”) transportation,
fractionation and marketing; (ii) storage of NGL and petrochemical products;
(iii) transportation of petrochemical products; and (iv) the gathering,
transportation, marketing and storage of natural gas.
At December 31, 2009, Duncan Energy
Partners was owned 99.3% by its limited partners and 0.7% by its general
partner, DEP GP, which is a wholly owned subsidiary of EPO. At
December 31, 2009, EPO owned approximately 58.6% of Duncan Energy Partners’
limited partner interests and 100% of DEP GP. DEP GP is responsible
for managing the business and operations of Duncan Energy Partners.
A privately held affiliate, EPCO,
provides all of our employees and certain administrative services to the
partnership.
The
following information summarizes the businesses acquired and consideration we
provided in connection with the DEP I and DEP II drop down
transactions.
DEP
I Drop Down
Effective
February 1, 2007, EPO contributed to us a 66% controlling equity interest in
each of the DEP I Midstream Businesses in a drop down
transaction. EPO retained the remaining 34% noncontrolling equity
interest in each of these businesses.
As consideration for these equity
interests, we paid $459.5 million in cash and issued 5,351,571 common units to
EPO. The cash portion of this consideration was financed with $198.9
million in borrowings under our $300.0 million unsecured revolving credit
facility (the “Revolving Credit Facility”) and $260.6 million of the $290.5
million of net proceeds from our initial public offering. The
following is a brief description of the assets and operations of the DEP I
Midstream Businesses:
|
§
|
Mont
Belvieu Caverns owns 34 underground salt dome storage caverns located in
Mont Belvieu, Texas, having an NGL and related product storage capacity of
approximately 100 million
barrels
|
|
|
(“MMBbls”),
and a brine system with approximately 20 MMBbls of above ground storage
capacity and two brine production
wells.
|
|
§
|
Acadian
Gas is engaged in the gathering, transportation, storage and marketing of
natural gas in south Louisiana, utilizing over 1,000 miles of
pipelines having an aggregate throughput capacity of 1.0 billion cubic
feet per day (“Bcf/d”). Acadian Gas also owns a 49.51% equity
interest in Evangeline, which owns a 27-mile natural gas pipeline located
in southeast Louisiana.
|
|
§
|
Lou-Tex
Propylene owns a 263-mile pipeline used to transport chemical-grade
propylene from Sorrento, Louisiana to Mont Belvieu,
Texas.
|
|
§
|
Sabine
Propylene owns a 21-mile pipeline used to transport polymer-grade
propylene from Port Arthur, Texas to a pipeline interconnect in Cameron
Parish, Louisiana.
|
|
§
|
South
Texas NGL owns a 297-mile pipeline system used to transport NGLs from our
Shoup and Armstrong NGL fractionation facilities in south Texas to Mont
Belvieu, Texas.
|
DEP
II Drop Down
On December 8, 2008, EPO contributed to
us the following controlling equity interests in a second drop down transaction:
(i) a 66% general partner interest in Enterprise GC, (ii) a 51% general partner
interest in Enterprise Intrastate and (iii) a 51% membership interest in
Enterprise Texas. As consideration for these equity interests, we
paid $280.5 million in cash and issued 37,333,887 Class B units to EPO (which
automatically converted on a one-for-one basis to common units in February
2009). The cash portion of this consideration was financed with
$280.0 million in borrowings under our $300.0 million senior unsecured term loan
agreement (the “Term Loan Agreement”) and $0.5 million of net cash proceeds from
an equity offering to EPO. The market value of the Class B units at
the time of issuance was approximately $449.5 million. The following
is a brief description of the assets and operations of the DEP II Midstream
Businesses:
|
§
|
Enterprise
GC operates and owns: (i) two NGL fractionation facilities, the Shoup and
Armstrong, located in south Texas; (ii) a 1,020-mile NGL pipeline system
located in south Texas; and (iii) 1,112 miles of natural gas gathering
pipelines located in south and west Texas. Enterprise GC’s
natural gas gathering pipelines include: (i) the 262-mile Big Thicket
Gathering System located in southeast Texas; (ii) the 660-mile Waha system
located in the Permian Basin of west Texas; and (iii) the 190-mile TPC
Offshore gathering system located in south
Texas.
|
|
§
|
Enterprise
Intrastate operates and owns an undivided 50% interest in the assets
comprising the 641-mile Channel natural gas pipeline, which extends from
the Agua Dulce Hub in south Texas to Sabine, Texas located on the
Texas/Louisiana border.
|
|
§
|
Enterprise
Texas owns the 6,560-mile Enterprise Texas natural gas pipeline system,
which includes the Sherman Extension, and leases the Wilson natural gas
storage facility. The Enterprise Texas system, along with the
Waha, TPC Offshore and Channel pipeline systems, comprise our Texas
Intrastate System.
|
See “Noncontrolling Interest – DEP II
Midstream Businesses – Parent” under Note 13 and “Significant Relationships and
Agreements with EPO – Company and Limited Partnership Agreements – DEP II
Midstream Businesses” under Note 15 for additional information.
Generally, to the extent that the DEP
II Midstream Businesses collectively generate cash sufficient to pay
distributions to EPO and us, such cash will be distributed first to us (based on
an initial defined investment of $730.0 million) and then to EPO in amounts
sufficient to generate an aggregate initial annualized return on their
respective investments of 11.85%. Effective January 1, 2010, the
annualized return increased by 2.0% to 12.087%. Distributions in
excess of these amounts will be distributed 98% to
EPO and
2% to us. Income and loss of the DEP II Midstream Businesses are
first allocated to EPO and us based on each entity’s percentage interest of
77.4% and 22.6%, respectively, and then in a manner that in part follows the
cash distributions.
See Note 13 for detailed information
regarding EPO’s noncontrolling interest in the DEP I and DEP II Midstream
Businesses.
Basis
of Financial Statement Presentation
Duncan Energy Partners, DEP GP, DEP
OLP, Enterprise Products Partners (including EPO and its consolidated
subsidiaries) and EPCO and affiliates are under common control of Dan L. Duncan,
the Group Co-Chairman and controlling shareholder of EPCO. Prior to
the drop down of controlling interests in the DEP I and DEP II Midstream
Businesses to Duncan Energy Partners, EPO owned these businesses and directed
their respective activities for all periods presented (to the extent such
businesses were in existence during such periods). Each of the drop
down transactions was accounted for at EPO’s historical costs as a
reorganization of entities under common control in a manner similar to a pooling
of interests. On a standalone basis, Duncan Energy Partners did not
own any assets prior to the completion of its initial public offering on
February 5, 2007 (February 1, 2007 for financial accounting and reporting
purposes).
Our consolidated financial statements
include the accounts of Duncan Energy Partners, and prior to the DEP I and DEP
II drop down transactions, the assets, liabilities and operations contributed to
us by EPO upon the closing of these drop down transactions. Our
financial statements have been prepared in accordance with generally accepted
accounting principles (“GAAP”) in the United States. The financial
statements of the DEP I and DEP II Midstream Businesses were prepared from the
separate records maintained by EPO and may not necessarily be indicative of the
conditions that would have existed or the results of operations if the DEP I and
DEP II Midstream Businesses had operated as unaffiliated
entities. All intercompany balances and transactions have been
eliminated in consolidation. Transactions between EPO and us have
been identified in our consolidated financial statements as transactions between
affiliates.
Our consolidated financial statements
for the year ended December 31, 2007 reflect the following:
|
§
|
Combined
financial information of the DEP I Midstream Businesses for the month of
January 2007. The results of operations and cash flows of the
DEP I Midstream Businesses for this one-month period are allocated to the
former owners of these businesses that are under common control with
Duncan Energy Partners. On February 5, 2007, these businesses
were contributed to Duncan Energy Partners in the DEP I drop down
transaction; therefore, the DEP I Midstream Businesses were consolidated
subsidiaries of Duncan Energy Partners for the eleven months ended
December 31, 2007. For financial accounting and reporting
purposes, the effective date of the DEP I drop down transaction is
February 1, 2007. EPO’s retained ownership in the DEP I
Midstream Businesses (following the drop down transaction) is presented in
our consolidated financial statements as “Noncontrolling interest in
subsidiaries – DEP I Midstream Businesses –
Parent.”
|
|
§
|
Combined
financial information of the DEP II Midstream Businesses for the year
ended December 31, 2007. The results of operations and cash
flows of the DEP II Midstream Businesses for this twelve-month period are
allocated to the former owners of these businesses that are under common
control with Duncan Energy
Partners.
|
Our consolidated financial statements
for the year ended December 31, 2008 reflect the following:
|
§
|
Combined
financial information of the DEP II Midstream Businesses from January 1,
2008 through December 7, 2008. The results of operations and
cash flows of the DEP II Midstream Businesses for this period are
allocated to the former owners of these businesses that are under common
control with Duncan Energy
Partners.
|
|
§
|
Consolidated
financial information for Duncan Energy Partners for the twelve months
ended December 31, 2008, including the results of operations and cash
flows for the DEP II Midstream Businesses following completion of the DEP
II drop down transaction. On December 8, 2008, the DEP II
Midstream Businesses were contributed to Duncan Energy Partners in the DEP
II drop down transaction; therefore, the DEP II Midstream Businesses
became consolidated subsidiaries of Duncan Energy Partners on this
date. EPO’s retained ownership in the DEP II Midstream
Businesses (following the December 8, 2008 drop down transaction) is
presented in our consolidated financial statements as “Noncontrolling
interest in subsidiaries – DEP II Midstream Businesses –
Parent.”
|
Allowance
for Doubtful Accounts
Our allowance for doubtful accounts
balance is determined based on specific identification and estimates of future
uncollectible accounts, as appropriate. Our procedure for recording
an allowance for doubtful accounts is based on: (i) our historical
experience; (ii) the financial stability of our customers; and
(iii) the levels of credit granted to customers. In addition, we
may also increase the allowance account in response to the specific
identification of customers involved in bankruptcy proceedings and those
experiencing other financial difficulties. On a routine basis, we
review estimates associated with the allowance for doubtful accounts to ensure
we have recorded sufficient reserves to cover potential losses. The
following financial statement schedule presents changes in our allowance for
doubtful account balances for the periods indicated:
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Balance
at beginning of period
|
$ | * | $ | * | $ | 0.4 | ||||||
|
Charges
to expense
|
-- | -- | -- | |||||||||
|
Deductions
|
* | -- | (0.4 | ) | ||||||||
|
Balance
at end of period
|
$ | * | $ | * | $ | * | ||||||
|
* Amounts
are negligible and less than $0.1 million.
|
||||||||||||
From time to time, we may also
establish an allowance for uncollectible natural gas imbalances based on
specific identification of accounts. At December 31, 2009 and 2008,
our allowance for uncollectible natural gas imbalances was zero. At
December 31, 2007, the balance was $5.4 million.
Cash
and Cash Equivalents
Cash and cash equivalents represent
unrestricted cash on hand and highly liquid investments with original maturities
of less than three months from the date of purchase.
The DEP I and DEP II Midstream
Businesses operated within the EPO cash management program prior to their
respective drop down transaction dates of February 1, 2007 and December 8,
2008. For purposes of presentation in our Statements of Consolidated
Cash Flows, cash flows provided by (or used in) financing activities during the
pre-drop down timeframes represent transfers of excess cash from the DEP I
and/or DEP II Midstream Businesses to their former owners in amounts equal to
any excess of net cash flow provided by operating activities over cash used in
investing activities. Such transfers of excess cash are shown as
permanent distributions to former owners on our Statements of Consolidated
Equity. Conversely, if cash used in investing activities was greater
than net cash flow provided by operating activities, then a deemed permanent
contribution by the former owners was recognized. As a result, our
financial statements do not reflect cash balances for the DEP I and DEP II
Midstream Businesses prior to their respective drop down transaction
dates. Following the DEP I and DEP II drop down transactions, the
respective businesses ceased participation in the EPO cash management program
and maintain cash
balances
separately from affiliates.
Consolidation
Policy
Our consolidated financial statements
include our accounts and those of our majority-owned subsidiaries in which we
have a controlling interest, after the elimination of all intercompany accounts
and transactions. We evaluate our financial interests in business
enterprises to determine if they represent variable interest entities where we
are the primary beneficiary. If such criteria are met, we consolidate
the financial statements of such businesses with those of our
own. Parent company ownership interests in our controlled
subsidiaries are presented as noncontrolling interests. See Note 13
for information regarding noncontrolling interest.
If an entity is organized as a limited
partnership or limited liability company and maintains separate ownership
accounts, we account for our investment using the equity method if our ownership
interest is between 3% and 50% and we exercise significant influence over the
investee’s operating and financial policies. For all other types of
investments, we apply the equity method of accounting if our ownership interest
is between 20% and 50% and we exercise significant influence over the investee’s
operating and financial policies. In consolidation, we eliminate our
proportionate share of profits and losses from transactions with equity method
unconsolidated affiliates to the extent such amounts remain on our Consolidated
Balance Sheets (or those of our equity method investments) in inventory or
similar accounts.
If our ownership interest in an
investee does not provide us with either control or significant influence over
the investee, we would account for the investment using the cost
method. We currently do not have any investments accounted for using
the cost method.
Contingencies
Certain conditions may exist as of the
date our financial statements are issued, which may result in a loss to us, but
which will only be resolved when one or more future events occur or fail to
occur. Our management and legal counsel evaluate such contingent
liabilities, and such evaluations inherently involve an exercise in
judgment. In assessing loss contingencies related to legal
proceedings that are pending against us or unasserted claims that may result in
proceedings, our management and legal counsel evaluate the perceived merits of
any legal proceedings or unasserted claims as well as the perceived merits of
the amount of relief sought or expected to be sought therein.
If the assessment of a contingency
indicates that it is probable that a material loss has been incurred and the
amount of liability can be estimated, then the estimated liability would be
accrued in our financial statements. If the assessment indicates that
a potential material loss contingency is not probable but is reasonably
possible, or is probable but cannot be estimated, then the nature of the
contingent liability, together with an estimate of the range of possible loss if
determinable, is disclosed.
Loss contingencies considered remote
are generally not disclosed unless they involve guarantees, in which case the
guarantees would be disclosed.
Current
Assets and Current Liabilities
We present, as individual captions in
our Consolidated Balance Sheets, all components of current assets and current
liabilities that exceed five percent of total current assets and liabilities,
respectively.
Deferred
Revenue
Amounts billed in advance of the period
in which the service is rendered or product delivered are recorded as deferred
revenue. At December 31, 2009 and 2008, deferred revenues totaled
$4.5 million and $7.2 million, respectively, and were recorded as a
component of other current and long-term liabilities as
appropriate
on our Consolidated Balance Sheets. See Note 4 for additional
information regarding our revenue recognition policies.
Derivative
Instruments
We use derivative instruments such as
swaps, forwards and other contracts to manage price risks associated with
inventories, firm commitments, interest rates and certain anticipated
transactions. To qualify for hedge accounting, the item to be hedged
must expose us to risk and the related derivative instrument must reduce that
exposure and meet specific documentation requirements. We formally
designate a derivative instrument as a hedge and document and assess the
effectiveness of the hedge at inception and thereafter on a quarterly basis. We
also apply the normal purchases/normal sales exception for certain of our
derivative instruments, which precludes the recognition of changes in
mark-to-market value for these items on the balance sheet or income
statement. Revenues and costs for these transactions are recognized when
volumes are physically delivered or received. See Note 6 for
additional information regarding our derivative instruments and related hedging
activities.
Earnings
per Unit
See Note 16 for more information
regarding our earnings per unit.
Environmental
Costs
Environmental costs for remediation are
accrued based on estimates of known remediation requirements. Such
accruals are based on management’s estimate of the ultimate cost to remediate a
site and are adjusted as further information and circumstances develop.
Those estimates may change substantially depending on information about the
nature and extent of contamination, appropriate remediation technologies and
regulatory approvals. Expenditures to mitigate or prevent future
environmental contamination are capitalized. Ongoing environmental
compliance costs are charged to expense as incurred. In accruing for
environmental remediation liabilities, costs of future expenditures for
environmental remediation are not discounted to their present value, unless the
amount and timing of the expenditures are fixed or reliably
determinable. At December 31, 2009, none of our estimated
environmental remediation liabilities were discounted to present value since the
ultimate amount and timing of cash payments for such liabilities were not
readily determinable.
The following table presents the
activity of our environmental reserves for the periods indicated:
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Balance
at beginning of period
|
$ | 0.6 | $ | 17.8 | $ | 20.7 | ||||||
|
Charges
to expense
|
0.1 | 0.5 | 0.3 | |||||||||
|
Deductions
(1)
|
(0.2 | ) | (17.7 | ) | (3.2 | ) | ||||||
|
Balance
at end of period
|
$ | 0.5 | $ | 0.6 | $ | 17.8 | ||||||
|
(1)
The
$17.7 million deduction in 2008 in the reserve balance is partially
comprised of a $5.0 million reduction in the reserve based on revised
estimates of future remediation costs and a remaining $6.3 million reserve
retained by EPO in connection with the DEP II drop down
transaction. In addition, we spent approximately $5.4 million for the
remediation of mercury site contamination in 2008.
|
||||||||||||
Equity
Awards
See Note 5 for information regarding
our accounting for equity awards.
Estimates
Preparing our financial statements in
conformity with GAAP requires management to make estimates and assumptions that
affect: (i) reported amounts of assets and liabilities; (ii) disclosure of
contingent assets and liabilities at the date of the financial statements; and
(iii) the reported amounts of revenues and expenses during a given
period. Our actual results could differ from these
estimates. On an ongoing basis, management reviews its estimates
based on currently available information. Changes in facts and
circumstances may result in revised estimates.
Fair
Value Information
Cash and cash equivalents, accounts
receivable, accounts payable, accrued expenses and other current liabilities are
carried at amounts which reasonably approximate their fair values due to their
short-term nature. The carrying amounts of our variable-rate debt
obligations reasonably approximate their fair values due to their variable
interest rates. See Note 6 for additional fair value information
associated with our derivative instruments.
The following table presents the
estimated fair values of our financial instruments at the dates
indicated:
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||
|
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||
|
Financial
Instruments
|
Value
|
Value
|
Value
|
Value
|
||||||||||||
|
Financial
assets:
|
||||||||||||||||
|
Cash
and cash equivalents
|
$ | 3.9 | $ | 3.9 | $ | 13.0 | $ | 13.0 | ||||||||
|
Accounts
receivable
|
142.0 | 142.0 | 156.3 | 156.3 | ||||||||||||
|
Financial
liabilities:
|
||||||||||||||||
|
Accounts
payable and accrued expenses
|
$ | 145.5 | $ | 145.5 | $ | 220.0 | $ | 220.0 | ||||||||
|
Other
current liabilities
|
18.9 | 18.9 | 33.3 | 33.3 | ||||||||||||
|
Variable-rate
revolving credit facility
|
175.0 | 175.0 | 202.0 | 202.0 | ||||||||||||
|
Variable-rate
term loan
|
282.3 | 282.3 | 282.3 | 282.3 | ||||||||||||
Impairment
Testing for Goodwill
Our goodwill amounts are assessed for
impairment (i) on a routine annual basis as of January 1 or (ii) when impairment
indicators are present. If such indicators occur (e.g., the loss of a
significant customer, economic obsolescence of plant assets, etc.), the
estimated fair value of the reporting unit to which the goodwill is assigned is
determined and compared to its book value. If the fair value of the
reporting unit exceeds its book value including associated goodwill amounts, the
goodwill is considered to be unimpaired and no impairment charge is
required. If the fair value of the reporting unit is less than its
book value including associated goodwill amounts, a charge to earnings is
recorded to reduce the carrying value of the goodwill to its implied fair
value. We have not recognized any impairment losses related to
goodwill for any of the periods presented. See Note 10 for additional
information regarding our goodwill.
Impairment
Testing for Long-Lived Assets
Long-lived assets (including intangible
assets with finite useful lives and property, plant and equipment) are reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amount of such assets may not be recoverable.
Long-lived assets with carrying values
that are not expected to be recovered through future cash flows are written down
to their estimated fair values. The carrying value of a long-lived
asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows
expected to result from the use and eventual disposition of the
asset. If the asset carrying value exceeds the sum of its
undiscounted cash flows, a non-cash asset impairment charge equal to the excess
of the asset’s carrying value over its estimated fair value is
recorded. Fair value is defined as the amount at which an asset or
liability could be
bought or
settled in an arm’s length transaction. We measure fair value using
market price indicators or, in the absence of such data, appropriate valuation
techniques. See Note 6 for information regarding impairment charges
recorded during 2009.
Impairment
Testing for Unconsolidated Affiliate
We evaluate our equity method
investment for impairment whenever events or changes in circumstances indicate
that there is a potential loss in value of the investment (other than a
temporary decline). Examples of such events or changes in
circumstances include continuing operating losses of the entity and/or long-term
negative changes in the entity’s industry. In the event we determine
that the loss in value of an investment is other than a temporary decline, we
record a charge to equity earnings to adjust the carrying value of the
investment to its estimated fair value. We had no such impairment
charges during the periods presented.
Income
Taxes
Provision for income taxes is primarily
applicable to our state tax obligations under the Revised Texas Franchise Tax
(the “Texas Margin Tax”). In general, legal entities that conduct
business in Texas are subject to the Texas Margin Tax. Such amounts
are considered immaterial to our financial statements.
Since we are structured as a
pass-through entity, we are not subject to federal income taxes. As a
result, our partners are individually responsible for paying federal income
taxes on their share of our taxable income. Deferred income tax
assets and liabilities are recognized for temporary differences between the
assets and liabilities of our tax paying entities for financial reporting and
tax purposes.
We recognize the tax effects of any
uncertain tax positions we may adopt, if the position taken by us is more likely
than not sustainable. If a tax position meets such criteria, the tax
effect to be recognized by us would be the largest amount of benefit with more
than a 50% chance of being realized upon settlement. We have not
taken any uncertain tax positions as defined by the Financial Accounting
Standards Board’s (“FASB”) accounting guidance on income taxes.
Inventories
Our inventory consists of natural gas
volumes that are used either for operational system balancing or held in
connection with forward sales contracts. We occasionally recognize
lower of average cost or market (“LCM”) adjustments when the historical cost of
our forward sales inventory exceeds its net realizable value. These
non-cash adjustments are recorded as a component of cost of sales within
operating costs and expenses. The capitalized cost of our inventory
held in connection with forward sales contracts includes shipping and handling
charges that are directly related to such volumes. As volumes are
delivered out of inventory, the cost of such inventory is charged to cost of
sales, which is a component of operating costs and
expenses. Transportation and handling fees associated with products
we deliver to customers are charged to operating costs and expenses as
incurred. The natural gas volumes used for operational system
balancing fluctuate as a result of imbalances with shippers and are valued based
on a twelve-month rolling average of posted industry prices. When
such volumes are delivered out of inventory, the average cost of these volumes
is charged against our accrued gas imbalance payables. See Note 7 for
additional information regarding our inventories.
Natural
Gas Imbalances
In the natural gas pipeline
transportation business, imbalances frequently result from differences in
natural gas volumes received from and delivered to our
customers. Such differences occur when a customer delivers more or
less gas into our pipelines than is physically redelivered back to them during a
particular time period. We have various fee-based agreements with
customers to transport their natural gas through our pipelines. Our
customers retain ownership of their natural gas shipped through our
pipelines. As such, our pipeline transportation activities are not
intended to create physical volume differences that
would
result in significant accounting or economic events for either our customers or
us during the course of the arrangement.
We settle pipeline gas imbalances
through either (i) physical delivery of in-kind gas or (ii) in
cash. These settlements follow contractual guidelines or common
industry practices. As imbalances occur, they may be settled: (i) on
a monthly basis; (ii) at the end of the agreement; or (iii) in accordance with
industry practice, including negotiated settlements. Certain of our
natural gas pipelines have a regulated tariff rate mechanism requiring customer
imbalance settlements each month at current market prices.
However, the vast majority of our
settlements are through in-kind arrangements whereby incremental volumes are
delivered to or received from a customer. Such in-kind deliveries are
ongoing and take place over several periods. In some cases,
settlements of imbalances built up over a period of time are ultimately cashed
out and are generally negotiated at values which approximate average market
prices over a period of time. For those gas imbalances that are
ultimately settled over future periods, we estimate the value of such current
assets and liabilities using average market prices, which we believe is
representative of the value of the imbalances upon final
settlement. Changes in natural gas prices may impact our
estimates.
The
following table presents our natural gas imbalance receivables/payables at the
dates indicated:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Natural
gas imbalance receivables
|
$ | 9.8 | $ | 35.7 | ||||
|
Natural
gas imbalance payables (1)
|
11.0 | 43.6 | ||||||
|
(1)
Reflected
as a component of “Accrued product payables” on our Consolidated Balance
Sheets.
|
||||||||
Property,
Plant and Equipment
Property, plant and equipment is
recorded at cost. Expenditures for additions, improvements and other
enhancements to property, plant and equipment are capitalized. Minor
replacements, maintenance, and repairs that do not extend asset life or add
value are charged to expense as incurred. When property, plant and
equipment assets are retired or otherwise disposed of, the related cost and
accumulated depreciation are removed from the accounts and any resulting gain or
loss is included in the results of operations for the respective
period.
In general, depreciation is the
systematic and rational allocation of an asset’s cost, less its residual value
(if any), to the periods it benefits. The majority of our property,
plant and equipment is depreciated using the straight-line method, which results
in depreciation expense being incurred evenly over the life of the
assets. Our estimate of depreciation incorporates assumptions
regarding the useful economic lives and residual values of our
assets. At the time we place our assets in service, we believe such
assumptions are reasonable. Under our depreciation policy for
midstream energy assets such as the Texas Intrastate System, the remaining
economic lives of such assets are limited to the estimated life of the natural
resource basins (based on proved reserves at the time of the analysis) from
which such assets derive their throughput volumes. Our forecast of
the remaining life for the applicable resource basins is based on several
factors, including information published by the U.S. Energy Information
Administration. Where appropriate, we use other depreciation methods
(generally accelerated) for tax purposes.
Leasehold improvements are recorded as
a component of property, plant and equipment. The cost of leasehold
improvements is charged to earnings using the straight-line method over the
shorter of the remaining lease term or the estimated useful lives of the
improvements. We consider renewal terms that are deemed reasonably
assured when estimating remaining lease terms.
Our assumptions regarding the useful
economic lives and residual values of our assets may change in response to new
facts and circumstances, which would change our depreciation amounts
prospectively. Examples of such circumstances include, but are not
limited to: (i) changes in laws and regulations that
limit the
estimated economic life of an asset; (ii) changes in technology that render
an asset obsolete; (iii) changes in expected salvage values; or (iv)
significant changes in the forecast life of proved reserves of applicable
resource basins, if any.
Certain of our plant operations require
periodic planned outages for major maintenance activities. These
planned shutdowns typically result in significant expenditures, which are
principally comprised of amounts paid to third parties for materials, contract
services and related items. We use the expense-as-incurred method for
any planned major maintenance activities.
Asset retirement obligations (“AROs”)
are legal obligations associated with the retirement of tangible long-lived
assets that result from their acquisition, construction, development and/or
normal operation. When an ARO is incurred, we record a liability for
the ARO and capitalize an equal amount as an increase in the carrying value of
the related long-lived asset. Over time, the liability is accreted to
its present value (accretion expense) and the capitalized amount is depreciated
over the remaining useful life of the related long-lived asset. We
will incur a gain or loss to the extent that our ARO liabilities are not settled
at their recorded amounts. See Note 8 for additional information
regarding our property, plant and equipment.
Revenue
Recognition
In general, we recognize revenue from
our customers when all of the following criteria are met: (i)
persuasive evidence of an exchange arrangement exists, (ii) delivery has
occurred or services have been rendered, (iii) the buyer’s price is fixed or
determinable and (iv) collectibility is reasonably assured. See Note
4 for information regarding our revenue recognition policies.
The accounting standard setting bodies
have recently issued the following guidance that will or may affect our future
financial statements:
Fair
Value Measurements. In January 2010, the
FASB issued new guidance to improve disclosures about fair value
measurements. This new guidance requires the following:
|
§
|
Effective
with the first quarter of 2010, additional disclosures will be required
regarding the reporting of transfers of fair value information between the
three levels of the fair value hierarchy (i.e., Levels 1, 2 and
3).
|
|
§
|
Effective
with the first quarter of 2011, companies will need to present purchases,
sales, issuances and settlements whose fair values are based on
unobservable inputs on a gross
basis.
|
Other than requiring enhanced fair
value disclosures, we do not expect our adoption of this guidance will have a
material impact on our consolidated financial statements.
Consolidation
of Variable Interest Entities. In June 2009, the
FASB amended its consolidation guidance regarding variable interest
entities. In general, this new guidance places more emphasis on a
qualitative analysis, rather than a purely quantitative approach, in determining
which company should consolidate a variable interest entity. Our
adoption of this guidance on January 1, 2010 did not have any impact on our
consolidated financial statements.
We recognize revenue using the
following criteria: (i) persuasive evidence of an exchange arrangement
exists; (ii) delivery has occurred or services have been rendered;
(iii) the buyer’s price is fixed
or
determinable; and (iv) collectibility is reasonably assured. The
following information provides a general description of our revenue recognition
policies by segment:
Natural
Gas Pipelines & Services
Our Natural Gas Pipelines &
Services include approximately 9,400 miles of onshore natural gas pipeline
systems that provide for the gathering and transportation of natural gas in
Louisiana and Texas. We lease natural gas storage facilities located
in Texas and Louisiana. This segment also includes our natural gas
marketing activities.
Our
natural gas pipelines typically generate revenues from transportation agreements
where shippers are billed a fee per unit of volume transported (typically per
million British thermal units, or “MMBtus”) multiplied by the volume gathered or
delivered. The transportation fees charged under these arrangements
are either contractual or regulated by governmental agencies, including the
Texas Railroad Commission. Certain of our natural gas pipelines offer
firm capacity reservation services whereby the shipper pays a contractually
stated fee based on the level of throughput capacity reserved in our pipelines
whether or not the shipper actually utilizes such capacity. In
connection with our natural gas transportation services and marketing
activities, intrastate natural gas pipelines (such as our Acadian Gas System)
may also purchase natural gas from producers and other suppliers for transport
and resale to customers such as electric utility companies, local natural gas
distribution companies, industrial users and other natural gas
marketing companies.
Revenues from natural gas storage
contracts typically have two components: (i) monthly demand payments, which are
associated with a customer’s storage capacity reservations and paid regardless
of actual usage and (ii) storage fees per unit of volume stored at our
facilities. Revenues from demand payments are recognized during the
period the customer reserves capacity. Revenues from storage fees are
recognized in the period the services are provided.
Our natural gas marketing activities
generate revenues from the sale and delivery of natural gas obtained from
third-party well-head purchases, regional natural gas processing plants and the
open market. Revenues from these sales contracts are recognized when
the natural gas is delivered to customers. In general, sales prices
referenced in these contracts are market-based and may include pricing
differentials for such factors as delivery location.
NGL
Pipelines & Services
Our NGL Pipelines & Services
include our (i) NGL marketing activities related to our Big Thicket Gathering
System; (ii) NGL pipelines aggregating 1,317 miles; (iii) NGL and related
product storage facilities and (iv) NGL fractionation facilities.
The NGL marketing activities of our Big
Thicket Gathering System generate revenues from the sale and delivery of NGLs
obtained through natural gas processing agreements at EPO’s Indian Springs
natural gas processing plant located in east Texas. The results of
operations from our NGL marketing activities are generally dependent upon the
volume of products sold and the market-based sales prices charged to
customers.
Under our
NGL pipeline transportation contracts, revenue is recognized when volumes have
been delivered to customers. Revenue from these contracts is
generally based upon a fixed fee per gallon of liquids transported multiplied by
the volume delivered. Transportation fees charged under these
arrangements are contractual and not typically regulated by governmental
agencies.
We collect storage revenues under our
NGL and related product storage contracts based on the number of days a customer
has volumes in storage multiplied by a storage rate (as defined in each
contract). Under these contracts, revenue is recognized ratably over
the length of the storage period. With respect to capacity
reservation agreements, we collect a fee for reserving storage capacity for
customers in our underground storage wells. Under these agreements,
revenue is recognized ratably over the specified reservation
period. Excess storage fees are collected when customers exceed their
reservation amounts and are recognized in the period of
occurrence. In addition, we derive brine production revenues from
customers that use brine in the production of feedstocks for polyvinyl
chloride.
We enter into fee-based arrangements
for the NGL fractionation services we provide to customers. Under
such fee-based arrangements, revenue is recognized in the period services are
provided. Such fee-based arrangements typically include a
base-processing fee (usually stated in cents per gallon) that is contractually
subject to adjustment for changes in certain fractionation expenses (e.g.
natural gas fuel costs).
Petrochemical
Services
Our Petrochemical Services consists of
our petrochemical pipelines aggregating 284 miles. Revenues recorded
for the Lou-Tex Propylene Pipeline and Sabine Propylene Pipeline are primarily
based on exchange agreements with Shell Oil Company and Exxon Mobil Corporation
(“Exxon Mobil”). As a result of these exchange agreements, we agree
to receive propylene in one location and deliver propylene at another location
for a fee. Revenue from these contracts is generally based upon a
fixed fee per unit of volume of liquids transported multiplied by the volume
delivered and may include deficiency fee provisions if certain minimum delivery
requirements are not met.
The following table summarizes the
expense we recognized in connection with equity-based awards issued under EPCO’s
long-term incentive plans for the periods presented (which awards relate to
units of affiliates other than Duncan Energy Partners L.P.):
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Restricted
unit awards (1)
|
$ | 1.4 | $ | 0.7 | $ | 0.3 | ||||||
|
Unit
option awards (1)
|
0.2 | -- | -- | |||||||||
|
Profits
interests awards (1)
|
0.6 | 0.2 | 0.2 | |||||||||
|
Total
compensation expense
|
$ | 2.2 | $ | 0.9 | $ | 0.5 | ||||||
|
(1)
Accounted
for as equity-classified awards. The fair value of an
equity-classified award is amortized to earnings on a straight-line basis
over the requisite service or vesting period.
|
||||||||||||
An allocated portion of the non-cash
amortization expense of these awards is charged to us under the administrative
services agreement (“ASA”) with EPCO. We recognize a non-cash expense
for our allocated share of the amortized grant date fair value of such awards,
with an offsetting amount recorded in equity. See Note 15 for a
general description of the ASA with EPCO. With the exception of
certain amounts recorded in connection with EPCO Unit, as defined later in this
note, we are not responsible for reimbursing EPCO for any other expenses
associated with such awards. Beginning in February 2009, the ASA was
amended to provide that we and other affiliates of EPCO will reimburse EPCO for
our allocated share of distributions of cash or securities made to the Class B
limited partners of EPCO Unit. Our reimbursements to EPCO during 2009
in connection with EPCO Unit were $0.1 million.
We have been allocated expense amounts
associated with the following long-term incentive plans of EPCO: (i)
the Enterprise Products 1998 Long-Term Incentive Plan (“1998 Plan”) and (ii) the
Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (“2008
Plan”).
The 1998 Plan provides for awards of
Enterprise Products Partners’ common units and other rights to non-employee
directors and to employees of EPCO and its affiliates providing services to
us. Awards under the 1998 Plan may be granted in the form of unit
options, restricted units, phantom units, unit appreciation rights (“UARs”) and
distribution equivalent rights (“DERs”). Up to 7,000,000 of
Enterprise Products Partners’ common units may be issued as awards under the
1998 Plan. After giving effect to awards granted under the plan
through December 31, 2009, a total of 652,543 additional common units of
Enterprise Products Partners could be issued. All of the awards
issued for which we have been allocated expense were in the form of unit options
and restricted units.
The 2008 Plan provides for awards of
Enterprise Products Partners’ common units and other rights to non-employee
directors and to consultants and employees of EPCO and its affiliates providing
services to us. Awards under the 2008 Plan may be granted in the form
of unit options, restricted units, phantom units, UARs and DERs. Up
to 10,000,000 of Enterprise Products Partners’ common units may be issued as
awards under the 2008 Plan. After giving effect to awards granted
under the plan through December 31, 2009, a total of 7,865,000 additional common
units of Enterprise Products Partners could be issued. All of the
awards issued for which we have been allocated expense were in the form of unit
options.
DEP
Unit Purchase Plan (“EUPP”) and
2010
Duncan Energy Partners L.P. Long-Term Incentive Plan (“2010 Plan”)
On December 10, 2009, the board of
directors of our general partner (the “Board”) unanimously approved a resolution
adopting both the 2010 Plan and the EUPP. The 2010 Plan provides for
awards of options to purchase common units, restricted common units, UARs,
phantom units and DERs to employees, directors or consultants providing services
to us and our subsidiaries. The EUPP provides eligible employees the
opportunity to purchase common units at a discount through withholdings from
eligible compensation. On December 30, 2009, the action taken by
the Board regarding the plans was approved by written consent of a subsidiary of
EPO, which held of record approximately 58.6% of our outstanding common units as
of that date. Because EPO’s subsidiary held a majority of our common
units as of December 30, 2009, no other votes were necessary to adopt the
plans. In February 2010, we filed a registration statement with the
SEC authorizing the issuance of up to 500,000 common units in connection with
the 2010 Plan and 500,000 common units in connection with the
EUPP. The plans became effective on February 11, 2010.
Summary
of EPCO long-term incentive plans
The following information is being
provided regarding EPCO’s long-term incentive plans under which we have or may
receive an allocation of expense. In addition to the 1998 Plan and
2008 Plan, EPCO’s active long-term incentive plans include the Enterprise
Products 2006 TPP Long-Term Incentive Plan (“2006 Plan”), under which unit
options, restricted units and other awards may be issued. EPCO also
has other plans under which liability-classified awards may be
issued. As of December 31, 2009, we have not been allocated any costs
of liability-classified awards and therefore have not included any discussion of
such plans in these disclosures. EPCO may create additional long-term
incentive plans in the future that may result in us receiving an allocation of
expense based on services rendered to us by the recipients of such
awards. Unless noted otherwise, the following information is
presented on a gross basis (to EPCO and affiliates) with respect to the type of
award granted. To the extent applicable, we have noted our estimated
share of unrecognized compensation costs of such awards and the weighted-average
period of time over which we expect to recognize such expense.
Restricted
Unit Awards
Restricted unit awards allow recipients
to acquire common units of Enterprise Products Partners (at no cost to the
recipient) once a defined vesting period expires, subject to customary
forfeiture provisions. The restrictions on such awards generally
lapse four years from the date of grant. The fair value of restricted
units is based on the market price per unit of the underlying security on the
date of grant. Compensation expense is recognized based on the grant
date fair value, net of an allowance for estimated forfeitures. As
used in the context of Enterprise Products Partners’ long-term incentive plans,
the term “restricted unit” represents a time-vested unit. Such awards
are non-vested until the required service period expires.
The following table summarizes
information regarding Enterprise Products Partners’ restricted unit awards for
the periods indicated:
|
Weighted-
|
||||||||
|
Average
Grant
|
||||||||
|
Number
of
|
Date
Fair Value
|
|||||||
|
Units
|
per Unit
(1)
|
|||||||
|
Restricted
units at December 31, 2006
|
1,105,237 | $ | 24.79 | |||||
|
Granted
(2)
|
738,040 | $ | 30.64 | |||||
|
Vested
|
(4,884 | ) | $ | 25.28 | ||||
|
Settled
or forfeited (3)
|
(149,853 | ) | $ | 23.31 | ||||
|
Restricted
units at December 31, 2007
|
1,688,540 | $ | 27.23 | |||||
|
Granted
(4)
|
766,200 | $ | 30.73 | |||||
|
Vested
|
(285,363 | ) | $ | 23.11 | ||||
|
Forfeited
|
(88,777 | ) | $ | 26.98 | ||||
|
Restricted
units at December 31, 2008
|
2,080,600 | $ | 29.09 | |||||
|
Granted
(5)
|
1,025,650 | $ | 24.89 | |||||
|
Vested
|
(281,500 | ) | $ | 26.70 | ||||
|
Forfeited
|
(411,884 | ) | $ | 28.37 | ||||
|
Awards
assumed in connection with TEPPCO Merger
|
308,016 | $ | 27.64 | |||||
|
Restricted
units at December 31, 2009
|
2,720,882 | $ | 27.70 | |||||
|
(1)
Determined
by dividing the aggregate grant date fair value of awards before an
allowance for forfeitures by the number of awards issued. With
respect to restricted unit awards assumed in connection with the TEPPCO
Merger, the weighted-average grant date fair value per unit was determined
by dividing the aggregate grant date fair value of the assumed awards
before an allowance for forfeitures by the number of awards
assumed.
(2)
Aggregate
grant date fair value of restricted unit awards issued during 2007 was
$22.6 million based on grant date market prices of Enterprise Products
Partners’ common units ranging from $28.00 to $31.83 per
unit. Estimated forfeiture rates ranging between 4.6% and 17% were
applied to these awards.
(3)
Reflects
the settlement of 113,053 restricted units in connection with the
resignation of EPGP’s former chief executive officer.
(4)
Aggregate
grant date fair value of restricted unit awards issued during 2008 was
$23.5 million based on grant date market prices of Enterprise Products
Partners’ common units ranging from $25.00 to $32.31 per unit. An
estimated forfeiture rate of 17% was applied to these awards.
(5)
Aggregate
grant date fair value of restricted unit awards issued during 2009 was
$25.5 million based on grant date market prices of Enterprise Products
Partners’ common units ranging from $20.08 to $28.73 per
unit. Estimated forfeiture rates ranging between 4.6% and 17% were
applied to these awards.
|
||||||||
On a gross basis, the total
unrecognized compensation cost of such awards was $37.9 million at December 31,
2009, of which our share is currently estimated to be $4.0
million. We expect to recognize our share of the unrecognized
compensation cost for these awards over a weighted-average period of 2.3
years.
Unit
Option Awards
Certain of Enterprise Products
Partners’ long-term incentive plans provide for the issuance of non-qualified
incentive options to purchase a fixed number of its common
units. When issued, the exercise price of each option grant may be no
less than the market price of the underlying security on the date
of
grant. In
general, options granted under the EPCO plans have a vesting period of four
years and remain exercisable for five to ten years, as applicable, from the date
of grant.
The fair value of each unit option is
estimated on the date of grant using the Black-Scholes option pricing model,
which incorporates various assumptions including expected life of the options,
risk-free interest rates, expected distribution yield on Enterprise Products
Partners’ common units, and expected unit price volatility of its common
units. In general, the assumption of expected life of the options
represents the period of time that the options are expected to be outstanding
based on an analysis of historical option activity. The selection of
the risk-free interest rate is based on published yields for U.S. government
securities with comparable terms. The expected distribution yield and
unit price volatility is estimated based on several factors, which include an
analysis of Enterprise Products Partners’ historical unit price volatility and
distribution yield over a period equal to the expected life of the
option.
During 2008, in response to changes in
the federal tax code applicable to certain types of equity awards, Enterprise
Products Partners amended the terms of certain of its outstanding unit
options. In general, the expiration dates of these awards were
modified from May and August 2017 to December 2012.
In order to fund its unit
option-related obligations, EPCO may purchase common units at fair value either
in the open market or directly from Enterprise Products Partners.
The following table presents unit
option activity under the EPCO plans for the periods indicated:
|
Weighted-
|
||||||||||||||||
|
Weighted-
|
Average
|
|||||||||||||||
|
Average
|
Remaining
|
Aggregate
|
||||||||||||||
|
Number
of
|
Strike
Price
|
Contractual
|
Intrinsic
|
|||||||||||||
|
Units
|
(dollars/unit)
|
Term
(in years)
|
Value
(1)
|
|||||||||||||
|
Outstanding
at December 31, 2006
|
2,416,000 | $ | 23.32 | |||||||||||||
|
Granted
(2)
|
895,000 | 30.63 | ||||||||||||||
|
Exercised
|
(256,000 | ) | 19.26 | |||||||||||||
|
Settled
or forfeited (3)
|
(740,000 | ) | 24.62 | |||||||||||||
|
Outstanding
at December 31, 2007
|
2,315,000 | 26.18 | ||||||||||||||
|
Granted
(4)
|
795,000 | 30.93 | ||||||||||||||
|
Exercised
|
(61,500 | ) | 20.38 | |||||||||||||
|
Forfeited
|
(85,000 | ) | 26.72 | |||||||||||||
|
Outstanding
at December 31, 2008
|
2,963,500 | 27.56 | ||||||||||||||
|
Granted
(5)
|
1,460,000 | 23.46 | ||||||||||||||
|
Exercised
|
(261,000 | ) | 19.61 | |||||||||||||
|
Forfeited
|
(930,540 | ) | 26.69 | |||||||||||||
|
Awards
assumed in connection with TEPPCO Merger
|
593,960 | 26.12 | ||||||||||||||
|
Outstanding at December 31,
2009 (6)
|
3,825,920 | 26.52 | 4.6 | $ | 2.8 | |||||||||||
|
Options
exercisable at:
|
||||||||||||||||
|
December
31, 2007
|
335,000 | $ | 22.06 | 4.0 | $ | 3.3 | ||||||||||
|
December
31, 2008
|
548,500 | $ | 21.47 | 4.1 | $ | -- | ||||||||||
|
December
31, 2009 (6)
|
447,500 | $ | 25.09 | 4.8 | $ | 2.8 | ||||||||||
|
(1)
Aggregate
intrinsic value reflects fully vested unit options at the date
indicated.
(2)
Aggregate
grant date fair value of these unit options issued during 2007 was $2.4
million based on the following assumptions: (i) a weighted-average grant
date market price of Enterprise Products Partners’ common units of $30.63
per unit; (ii) expected life of options of 7.0 years; (iii)
weighted-average risk-free interest rate of 4.8%; (iv) weighted-average
expected distribution yield on Enterprise Products Partners’ common units
of 8.4%; and (v) weighted-average expected unit price volatility on
Enterprise Products Partners’ common units of 23.2%.
(3)
Includes
the settlement of 710,000 options in connection with the resignation of
EPGP’s chief executive officer.
(4)
Aggregate
grant date fair value of these unit options issued during 2008 was $1.9
million based on the following assumptions: (i) a grant date market price
of Enterprise Products Partners’ common units of $30.93 per unit; (ii)
expected life of options of 4.7 years; (iii) a risk-free interest rate of
3.3%; (iv) an expected distribution yield on Enterprise Products Partners’
common units of 7.0%; and (v) an expected unit price volatility on
Enterprise Products Partners’ common units of 19.8%. An estimated
forfeiture rate of 17.0% was applied to awards granted during
2008.
(5)
Aggregate
grant date fair value of these unit options issued during 2009 was $8.1
million based on the following assumptions: (i) a weighted-average grant
date market price of Enterprise Products Partners’ common units of $23.46
per unit; (ii) weighted-average expected life of options of 4.8 years;
(iii) weighted-average risk-free interest rate of 2.1%; (iv)
weighted-average expected distribution yield on Enterprise Products
Partners’ common units of 9.4%; and (v) weighted-average expected unit
price volatility on Enterprise Products Partners’ common units of
57.4%. An estimated forfeiture rate of 17.0% was applied to awards
granted during 2009.
(6)
Enterprise
Products Partners was committed to issue 3,825,920 and 2,963,500 of
Enterprise Products Partners’ common units at December 31, 2009 and 2008,
respectively, if all outstanding options awarded (as of these dates) were
exercised. Of the option awards outstanding at December 31, 2009, an
additional 410,000, 712,280, 736,000 and 1,520,140 are exercisable in
2010, 2012, 2013 and 2014, respectively.
|
||||||||||||||||
On a gross basis, the total
unrecognized compensation cost of such awards was $7.3 million at December 31,
2009, of which our share is currently estimated to be $0.6
million. We expect to recognize our share of the unrecognized
compensation cost for these awards over a weighted-average period of 2.9
years.
Profits
Interests Awards
As long-term incentive arrangements,
EPCO has granted its key employees who perform services on behalf of us, EPCO
and other affiliated companies, “profits interests” in several limited
partnerships (the “Employee Partnerships”), all of which are privately held
affiliates of EPCO. Profits interests awards entitle
each holder to participate in the expected long-term appreciation in value of
the equity securities
owned by
each Employee Partnership. The Employee Partnerships in which our
named executive officers participate own either units of Enterprise GP Holdings
or Enterprise Products Partners or a combination of both. The profits
interests awards are subject to customary forfeiture provisions.
Each Employee Partnership has a single
Class A limited partner, which is a privately held indirect subsidiary of EPCO,
and a varying number of Class B limited partners. At formation, the
Class A limited partner either contributes cash or limited partner units it owns
to the Employee Partnership. If cash is contributed, the Employee
Partnership uses these funds to acquire limited partner units on the open
market. In general, the Class A limited partner earns a preferred
return (either fixed or variable depending on the partnership agreement) on its
investment (or “Capital Base”) in the Employee Partnership and residual
quarterly cash amounts, if any, are distributed to the Class B limited
partners. Upon liquidation, Employee Partnership assets having a fair
market value equal to the Class A limited partner’s Capital Base, plus any
preferred return for the period in which liquidation occurs, will be distributed
to the Class A limited partner. Any remaining assets will be
distributed to the Class B limited partner(s) as a residual profits interest and
are a factor of the appreciation in value of the partnership’s assets since its
formation date.
The grant date fair value of each
Employee Partnership is based on (i) the estimated value of the remaining
assets, as determined using a Black-Scholes option pricing model, that would be
distributed to the Class B limited partners upon dissolution of the Employee
Partnership and (ii) the value, based on a discounted cash flow analysis using
appropriate discount rates, of the residual quarterly cash amounts that the
Class B limited partners are expected to receive over the life of the Employee
Partnership.
The following table summarizes key
elements of each Employee Partnership as of December 31, 2009. As
used in the table in reference to the description of assets, “EPE” means
Enterprise GP Holdings L.P. and “EPD” means Enterprise Products Partners
L.P.
|
Initial
|
Class
A
|
||||||||
|
Class
A
|
Partner
|
Grant
Date
|
Unrecognized
|
||||||
|
Employee
|
Description
|
Capital
|
Preferred
|
Liquidation
|
Fair
Value
|
Compensation
|
|||
|
Partnership
|
of
Assets
|
Base
|
Return
|
Date
(1)
|
of
Awards
|
Cost
|
|||
|
EPE
Unit I
|
1,821,428
EPE units
|
$51.0
million
|
4.50% to
5.725%
|
February
2016
|
$21.5
million
|
$12.1
million
|
|||
|
EPE
Unit II
|
40,725
EPE units
|
$1.5
million
|
4.50% to
5.725%
|
February
2016
|
$0.4
million
|
$0.3
million
|
|||
|
EPE
Unit III
|
4,421,326
EPE units
|
$170.0
million
|
3.80% |
February
2016
|
$42.8
million
|
$30.8
million
|
|||
|
Enterprise
Unit
|
881,836
EPE units
844,552
EPD units
|
$51.5
million
|
5.00% |
February
2016
|
$6.5
million
|
$5.3
million
|
|||
|
EPCO
Unit
|
779,102
EPD units
|
$17.0
million
|
4.87% |
February
2016
|
$8.1
million
|
$6.5
million
|
|||
|
(1)
The
liquidation date may be accelerated for change of control and other events
as described in the underlying partnership
agreements.
|
|||||||||
The total
unrecognized compensation cost of the profits interests awards was $55.0 million
at December 31, 2009 of which our share is currently estimated to be $3.8
million. We expect to recognize our share of the unrecognized
compensation cost for these awards over a weighted-average period of 6.1
years.
In December 2009, the expected
liquidation date for each Employee Partnership was extended to February
2016. This modification follows a similar set of modifications made
in July 2008 for EPE Unit I, EPE Unit II and EPE Unit III that extended
liquidation dates as well as reduced the Class A limited partner’s preferred
return rates. These modifications are intended to align the interests
of the employee partners of the Employee Partnerships with the long-term
interests of EPCO and other unitholders in the
relevant
underlying publicly traded partnerships, which also hold indirectly a
significant ownership interest in both us and our subsidiaries.
The following table presents the impact
of modifications (e.g., extension of liquidation dates) and other changes on the
aggregate grant date fair value (on an unallocated basis) of the Employee
Partnerships for the periods presented.
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Aggregate
grant date fair values at beginning of period
|
$ | 64.6 | $ | 35.4 | $ | 12.8 | ||||||
|
New
Employee Partnership grants (1,2)
|
-- | 14.6 | 23.0 | |||||||||
|
Award
modifications
|
19.5 | 15.0 | -- | |||||||||
|
Other
adjustments, primarily forfeiture and regrant activity (2)
|
(4.8 | ) | (0.4 | ) | (0.4 | ) | ||||||
|
Aggregate
grant date fair value at end of period
|
$ | 79.3 | $ | 64.6 | $ | 35.4 | ||||||
|
(1)
EPE
Unit III was formed in 2007 and EPCO Unit and Enterprise Unit were formed
in 2008.
(2)
TEPPCO
Unit L.P. and TEPPCO Unit II L.P. were formed during 2008 and dissolved
during 2009.
|
||||||||||||
The following table summarizes the
assumptions used in deriving that portion of the estimated grant date fair value
for each Employee Partnership using a Black-Scholes option pricing
model:
|
Expected
|
Risk-Free
|
Expected
|
Expected
Unit
|
|
|
Employee
|
Life
|
Interest
|
Distribution
|
Price
|
|
Partnership
|
of
Award
|
Rate
|
Yield
|
Volatility
|
|
EPE
Unit I
|
3
to 6 years
|
1.2%
to 5.0%
|
3.0%
to 6.7%
|
16.6%
to 35.0%
|
|
EPE
Unit II
|
4
to 6 years
|
1.6%
to 4.4%
|
3.8%
to 6.4%
|
18.7%
to 31.7%
|
|
EPE
Unit III
|
4
to 6 years
|
1.4%
to 4.9%
|
4.0%
to 6.4%
|
16.6%
to 32.2%
|
|
Enterprise
Unit
|
4
to 6 years
|
1.4%
to 3.9%
|
4.5%
to 8.4%
|
15.3%
to 31.7%
|
|
EPCO
Unit
|
4
to 6 years
|
1.6%
to 2.4%
|
8.1%
to 11.1%
|
27.0%
to 50.0%
|
In the course of our normal business
operations, we are exposed to certain risks, including changes in interest rates
and commodity prices. In order to manage risks associated with
certain identifiable and anticipated transactions, we use derivative
instruments. Derivatives are instruments whose fair value is
determined by changes in a specified benchmark such as interest rates or
commodity prices. Fair value is generally defined as the amount at
which a derivative instrument could be exchanged in a current transaction
between willing parties, not in a forced sale. Typical derivative
instruments include futures, forward contracts, swaps, options and other
instruments with similar characteristics. Substantially all of our
derivatives are used for non-trading activities.
We are required to recognize derivative
instruments at fair value as either assets or liabilities on the balance
sheet. While all derivatives are required to be reported at fair
value on the balance sheet, changes in fair value of the derivative instruments
are reported in different ways, depending on the nature and effectiveness of the
hedging activities to which they are related. After meeting specified
conditions, a qualified derivative may be specifically designated as a total or
partial hedge of:
|
§
|
Changes
in the fair value of a recognized asset or liability, or an unrecognized
firm commitment - In a fair value hedge, gains and losses for both the
derivative instrument and the hedged item are recognized in income during
the period of change.
|
|
§
|
Variable
cash flows of a forecasted transaction - In a cash flow hedge, the
effective portion of the hedge is reported in other comprehensive income
(“OCI”) and is reclassified into earnings when the forecasted transaction
affects earnings.
|
An
effective hedge relationship is one in which the change in fair value of a
derivative instrument can be expected to offset 80% to 125% of changes in the
fair value of a hedged item at inception and throughout the life of the hedging
relationship. The effective portion of a hedge relationship is the
amount by which the derivative instrument exactly offsets the change in fair
value of the hedged item during the reporting period. Conversely,
ineffectiveness represents the change in the fair value of the derivative
instrument that does not exactly offset the change in the fair value of the
hedged item. Any ineffectiveness associated with a hedge relationship
is recognized in earnings immediately. Ineffectiveness can be caused
by, among other things, changes in the timing of forecasted transactions or a
mismatch of terms between the derivative instrument and the hedged
item.
A contract designated as a cash flow
hedge of an anticipated transaction that is probable of not occurring is
immediately recognized in earnings.
Interest
Rate Derivative Instruments
We utilize interest rate swaps to
manage our exposure to changes in the interest rates of certain consolidated
debt agreements. This strategy is a component in controlling our cost
of capital associated with such borrowings.
The following table summarizes our
interest rate derivative instruments outstanding at December 31, 2009, all of
which were designated as hedging instruments under the FASB’s derivative and
hedging guidance:
|
Number
|
Period
Covered
|
Termination
|
Variable
to
|
Notional
|
||||
|
Hedged
Variable Rate Debt
|
of
Swaps
|
by
Swap
|
Date
of Swap
|
Fixed Rate
(1)
|
Value
|
|||
|
Revolving
Credit Facility, due Feb. 2011
|
3 |
Sep.
2007 to Sep. 2010
|
Sep.
2010
|
0.25% to
4.62%
|
$175.0
million
|
|||
|
(1)
Amounts
receivable from or payable to the swap counterparties are settled every
three months.
|
||||||||
Cash flow hedges fix the interest rate
paid on floating rate debt with the difference between the floating rate and
fixed rate being recorded as an increase/decrease to interest expense.
This combined activity resulted in an increase of interest expense of $6.5
million and $2.0 million, respectively, for 2009 and 2008.
For information regarding consolidated
fair value amounts and gains and losses on interest rate derivative instruments
and related hedged items, see “Tabular Presentation of Fair Value Amounts, and
Gains and Losses on Derivative Instruments and Related Hedged Items” within this
Note 6.
Commodity
Derivative Instruments
The price of natural gas is subject to
fluctuations in response to changes in supply and demand, market conditions and
a variety of additional factors that are beyond our control. In order
to manage the price risk associated with certain exposures, we enter into
commodity derivative instruments such as forwards, basis swaps and futures
contracts. The following table summarizes the absolute notional
amount of our commodity derivative instruments outstanding at December 31,
2009:
|
Volume
|
Accounting
|
||
|
Derivative
Purpose
|
Current
|
Long-Term
|
Treatment
|
|
Derivatives
not designated as hedging instruments:
|
|||
|
Acadian
Gas:
|
|||
|
Natural
gas risk management activities
|
2.2
Bcf
|
n/a
|
Mark-to-market
|
At December 31, 2009, none of our
derivative instruments met hedge accounting requirements; therefore, they are
accounted for using mark-to-market accounting.
Our hedging strategy is intended to
reduce the variability of future earnings and cash flows resulting from changes
in natural gas prices. We enter into a limited number of forward
transactions that effectively fix the price of natural gas for certain customers
and hedge the resulting exposure with derivative instruments. We may
also enter into a small number of cash flow hedges in connection with the
purchase of natural gas held-for-sale to third parties.
Historically, the use of commodity
derivative instruments was governed by policies established by the general
partner of Enterprise Products Partners. Our general partner now
monitors the hedging strategies associated with these physical and financial
risks, approves specific activities subject to the policy (including authorized
products, instruments and markets) and establishes specific guidelines and
procedures for implementing and ensuring compliance with the
policy.
For information regarding consolidated
fair value amounts and gains and losses on commodity derivative instruments and
related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains
and Losses on Derivative Instruments and Related Hedged Items” within this Note
6.
Credit-Risk
Related Contingent Features in Derivative Instruments
Commodity derivative instruments can
include provisions related to minimum credit ratings and/or adequate assurance
clauses. At December 31, 2009, we did not have any derivative instruments
in a net liability position. The potential for derivatives with
contingent features to enter a net liability position may change in the future
as positions and prices fluctuate.
Tabular
Presentation of Fair Value Amounts, and Gains and Losses on
Derivative
Instruments and Related Hedged Items
The following table provides a balance
sheet overview of our derivative assets and liabilities at the dates
indicated:
|
Asset
Derivatives
|
Liability
Derivatives
|
|||||||||||||||||||
|
December
31, 2009
|
December
31, 2008
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||||
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
|||||||||||||
|
Location
|
Value
|
Location
|
Value
|
Location
|
Value
|
Location
|
Value
|
|||||||||||||
|
Derivatives designated as hedging
instruments:
|
||||||||||||||||||||
|
Interest
rate derivatives
|
Other
current assets
|
$ | -- |
Other
current assets
|
$ | -- |
Other
current liabilities
|
$ | 5.5 |
Other
current liabilities
|
$ | 5.9 | ||||||||
|
Interest
rate derivatives
|
Other
assets
|
-- |
Other
assets
|
-- |
Other
liabilities
|
-- |
Other
liabilities
|
3.9 | ||||||||||||
|
Total
derivatives
|
||||||||||||||||||||
|
designated
as hedging
|
||||||||||||||||||||
|
instruments
|
$ | -- | $ | -- | $ | 5.5 | $ | 9.8 | ||||||||||||
|
Derivatives not designated as hedging
instruments:
|
||||||||||||||||||||
|
Commodity
derivatives
|
Other
current assets
|
$ | 0.1 |
Other
current assets
|
$ | 1.9 |
Other
current liabilities
|
$ | 0.1 |
Other
current liabilities
|
$ | 2.0 | ||||||||
|
Total
derivatives not
|
||||||||||||||||||||
|
designated
as hedging
|
||||||||||||||||||||
|
instruments
|
$ | 0.1 | $ | 1.9 | $ | 0.1 | $ | 2.0 | ||||||||||||
The following tables present the effect
of our derivative instruments designated as cash flow hedges on our Statements
of Consolidated Operations for the periods presented:
|
Change
in Value
|
||||||||
|
Derivatives
in
|
Recognized
in OCI on
|
|||||||
|
Cash
Flow
|
Derivative
|
|||||||
|
Hedging
Relationships
|
(Effective
Portion)
|
|||||||
|
For
the Twelve Months
|
||||||||
|
Ended
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Interest
rate
|
$ | (2.5 | ) | $ | (8.0 | ) | ||
|
Commodity
|
-- | (0.7 | ) | |||||
|
Total
|
$ | (2.5 | ) | $ | (8.7 | ) | ||
|
Derivatives
in
|
Location
of Loss Reclassified from
AOCI |
Amount
of Loss Reclassified from
AOCI |
|||||||
|
Cash
Flow
Hedging
Relationships
|
into
Income
(Effective
Portion)
|
into
Income
(Effective
Portion)
|
|||||||
|
For
the Twelve Months
|
|||||||||
|
Ended
December 31,
|
|||||||||
|
2009
|
2008
|
||||||||
|
Interest
rate
|
Interest
expense
|
$ | (6.6 | ) | $ | (2.0 | ) | ||
|
Commodity
|
Operating
Revenue
|
-- | (0.7 | ) | |||||
|
Total
|
$ | (6.6 | ) | $ | (2.7 | ) | |||
|
Amount
of Gain
|
|||||||||
|
Derivatives
in Cash Flow
|
Recognized
in Income on
|
||||||||
|
Hedging
Relationships
|
Location
|
Ineffective
Portion of Derivative
|
|||||||
|
For
the Twelve Months
|
|||||||||
|
Ended
December 31,
|
|||||||||
|
2009
|
2008
|
||||||||
|
Interest
rate derivatives
|
Interest
expense
|
$ | 0.1 | $ | * | ||||
|
Total
|
$ | 0.1 | $ | * | |||||
|
*
Indicates that amounts are negligible and less than $0.1
million.
|
|||||||||
Over the next twelve months, we expect
to reclassify $5.4 million of AOCI attributable to interest rate derivative
instruments into earnings as an increase to interest expense, based on the
current level of interest rates.
The following table presents the effect
of our derivative instruments not designated as hedging instruments on our
Statements of Consolidated Operations for the periods presented:
|
Gain/(Loss)
Recognized in
|
|||||||||
|
Derivatives
Not Designated
|
Income
on Derivative
|
||||||||
|
as
Hedging Instruments
|
Location
|
Amount
|
|||||||
|
For
the Twelve Months
|
|||||||||
|
Ended
December 31,
|
|||||||||
|
2009
|
2008
|
||||||||
|
Commodity
derivatives
|
Revenue
|
$ | (0.6 | ) | $ | 0.7 | |||
|
Total
|
$ | (0.6 | ) | $ | 0.7 | ||||
Fair
Value Measurements
Fair value is defined as the price that
would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at a specified measurement
date. Our fair value estimates are based on either (i) actual market
data or (ii) assumptions that other market participants would use in pricing an
asset or liability, including estimates of risk. Recognized valuation
techniques employ inputs such as product prices, operating costs, discount
factors and business growth rates. These inputs
may be either readily observable, corroborated by market data or generally
unobservable. In
developing
our estimates of fair value, we endeavor to utilize the best information
available and apply market-based data to the extent
possible. Accordingly, we utilize valuation techniques (such as the
market approach) that maximize the use of observable inputs and minimize the use
of unobservable inputs.
A three-tier hierarchy has been
established that classifies fair value amounts recognized or disclosed in the
financial statements based on the observability of inputs used to estimate such
fair values. The hierarchy considers fair value amounts based on
observable inputs (Levels 1 and 2) to be more reliable and predictable than
those based primarily on unobservable inputs (Level 3). At each
balance sheet reporting date, we categorize our financial assets and liabilities
using this hierarchy. The characteristics of fair value amounts
classified within each level of the hierarchy are described as
follows:
|
§
|
Level
1 fair values are based on quoted prices, which are available in active
markets for identical assets or liabilities as of the measurement
date. Active markets are defined as those in which transactions
for identical assets or liabilities occur with sufficient frequency so as
to provide pricing information on an ongoing basis (e.g., the New York
Mercantile Exchange). Our Level 1 fair values primarily consist
of financial assets and liabilities such as exchange-traded commodity
financial instruments.
|
|
§
|
Level
2 fair values are based on pricing inputs other than quoted prices in
active markets (as reflected in Level 1 fair values) and are either
directly or indirectly observable as of the measurement
date. Level 2 fair values include instruments that are valued
using financial models or other appropriate valuation
methodologies. Such financial models are primarily
industry-standard models that consider various assumptions, including
quoted forward prices for commodities, the time value of money, volatility
factors, current market and contractual prices for the underlying
instruments and other relevant economic measures. Substantially
all of these assumptions are: (i) observable in the marketplace throughout
the full term of the instrument; (ii) can be derived from observable data;
or (iii) are validated by inputs other than quoted prices (e.g., interest
rate and yield curves at commonly quoted intervals). Our Level
2 fair values primarily consist of commodity financial instruments such as
forwards, swaps and other instruments transacted on an exchange or over
the counter. The fair values of these derivatives are based on
observable price quotes for similar products and locations. Our
interest rate derivatives are valued by using appropriate financial models
with the implied forward London Interbank Offered Rate (“LIBOR”) yield
curve for the same period as the future interest swap
settlements.
|
|
§
|
Level
3 fair values are based on unobservable inputs. Unobservable
inputs are used to measure fair value to the extent that observable inputs
are not available, thereby allowing for situations in which there is
little, if any, market activity for the asset or liability at the
measurement date. Unobservable inputs reflect the reporting
entity’s own ideas about the assumptions that market participants would
use in pricing an asset or liability (including assumptions about
risk). Unobservable inputs are based on the best information
available in the circumstances, which might include the reporting entity’s
internally developed data. The reporting entity must not ignore
information about market participant assumptions that is reasonably
available without undue cost and effort. Level 3 inputs are
typically used in connection with internally developed valuation
methodologies where management makes its best estimate of an instrument’s
fair value. Level 3 generally includes specialized or unique
financial instruments that are tailored to meet a customer’s specific
needs. At December 31, 2009, we did not have any Level 3
financial assets or liabilities.
|
The following tables set forth, by
level within the fair value hierarchy, our financial assets and liabilities
measured on a recurring basis at the dates indicated. These financial
assets and liabilities are classified in their entirety based on the lowest
level of input that is significant to the fair value measurement. Our
assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of the fair value
assets and liabilities, in addition to their placement within the fair value
hierarchy levels.
|
At
December 31, 2009
|
||||||||||||
|
Level
1
|
Level
2
|
Total
|
||||||||||
|
Financial
assets:
|
||||||||||||
|
Commodity
derivative instruments
|
$ | 0.1 | $ | * | $ | 0.1 | ||||||
|
Financial
liabilities:
|
||||||||||||
|
Commodity
derivative instruments
|
$ | * | $ | 0.1 | $ | 0.1 | ||||||
|
Interest
rate derivative instruments
|
-- | 5.5 | 5.5 | |||||||||
|
Total
derivative liabilities
|
$ | * | $ | 5.6 | $ | 5.6 | ||||||
|
*
Indicates that amounts are negligible and less than $0.1
million.
|
||||||||||||
|
At
December 31, 2008
|
||||||||||||
|
Level
1
|
Level
2
|
Total
|
||||||||||
|
Financial
assets:
|
||||||||||||
|
Commodity
derivative instruments
|
$ | * | $ | 1.9 | $ | 1.9 | ||||||
|
Financial
liabilities:
|
||||||||||||
|
Commodity
derivative instruments
|
$ | 1.9 | $ | 0.1 | $ | 2.0 | ||||||
|
Interest
rate derivative instruments
|
-- | 9.8 | 9.8 | |||||||||
|
Total
derivative liabilities
|
$ | 1.9 | $ | 9.9 | $ | 11.8 | ||||||
|
*
Indicates that amounts are negligible and less than $0.1
million.
|
||||||||||||
Nonfinancial
Assets and Liabilities
Certain nonfinancial assets and
liabilities are measured at fair value on a nonrecurring basis and are subject
to fair value adjustments in certain circumstances (e.g., when there is evidence
of impairment). The following table presents the estimated fair value
of certain assets carried on our Consolidated Balance Sheet by caption for which
a nonrecurring change in fair value has been recorded during the year ended
December 31, 2009:
|
Level
3
|
Impairment
Charges
|
|||||||
|
Property,
plant and equipment
|
$ | 1.8 | $ | 4.2 | ||||
Using appropriate valuation techniques,
we adjusted the carrying value of certain of our Natural Gas Pipelines and
Services segment assets when we recorded a non-cash asset impairment charge of
$3.3 million due to the cancellation of a compressor station project on our
Texas Intrastate System. We also adjusted the carrying value of
certain pipeline segments of the Texas Intrastate System to fair value during
2009. Anticipated abandonment activities related to a portion of this
system led to a non-cash impairment charge of $0.9 million. These
impairment charges are reflected in operating costs and expenses for the year
ended December 31, 2009.
Our inventory amounts were as follows
at the dates indicated:
|
December
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Working
inventory (1)
|
$ | 4.4 | $ | 18.3 | ||||
|
Forward
sales inventory (2)
|
6.1 | 9.7 | ||||||
|
Total
inventory
|
$ | 10.5 | $ | 28.0 | ||||
|
(1) Working
inventory is comprised of inventories of natural gas that are used in the
provision for services.
(2)
Forward
sales inventory consists of identified natural gas volumes dedicated to
the fulfillment of forward sales contracts.
|
||||||||
Working inventory includes natural gas
volumes held for operational system balancing on the Texas Intrastate
System. These natural gas inventories fluctuate as a result of
imbalances with shippers and are valued based on a twelve-month rolling average
of posted industry prices. When such volumes are delivered out of
inventory, the average cost of these volumes is charged against our accrued gas
imbalance payables. At December 31, 2009 and 2008, the value of
natural gas held in inventory for operational system balancing was $2.8 million
and $15.5 million, respectively.
As a result of fluctuating market
conditions, we occasionally recognize LCM adjustments when the historical cost
of our forward sales inventory exceeds its net realizable
value. These non-cash adjustments are recorded as a component of cost
of sales in the period they are recognized and generally affect our segment
operating results in the following manner:
|
§
|
Write-downs
of natural gas inventories are recorded as an expense related to our
natural gas pipeline operations within our Natural Gas Pipelines &
Services business segment.
|
To the extent our commodity hedging
strategies address inventory-related risks and are successful, these inventory
valuation adjustments are mitigated or offset. See Note 6 for a
description of our commodity hedging activities.
The
following table summarizes our cost of sales and LCM adjustments for the periods
indicated:
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Cost
of sales (1)
|
$ | 490.0 | $ | 1,122.4 | $ | 811.4 | ||||||
|
LCM
adjustments
|
* | 1.8 | 0.3 | |||||||||
|
(1)
Cost
of sales is included in operating costs and expenses, as presented on our
Statements of Consolidated Operations. The fluctuation in this amount
year-to-year is primarily due to changes in natural gas
prices.
|
||||||||||||
| * We recognized nominal LCM adjustments for the year ended December 31, 2009. |
Our property, plant and equipment
values and accumulated depreciation balances were as follows at the dates
indicated:
|
Estimated
Useful
|
At
December 31,
|
|||||||||||
|
Life
in Years
|
2009
|
2008
|
||||||||||
|
Plant
and pipeline facilities (1)
|
3-45(4) | $ | 4,767.0 | $ | 4,175.0 | |||||||
|
Underground
storage wells and related assets (2)
|
5-35(5) | 432.5 | 407.9 | |||||||||
|
Transportation
equipment (3)
|
3-10 | 11.3 | 10.3 | |||||||||
|
Land
|
27.8 | 23.9 | ||||||||||
|
Construction
in progress
|
233.6 | 459.0 | ||||||||||
|
Total
|
5,472.2 | 5,076.1 | ||||||||||
| Less accumulated depreciation | 922.6 | 745.9 | ||||||||||
|
Property,
plant and equipment, net
|
$ | 4,549.6 | $ | 4,330.2 | ||||||||
|
(1)
Includes
natural gas, NGL and petrochemical pipelines, NGL fractionation plants,
office furniture and equipment, buildings, and related
assets.
(2)
Underground
storage facilities include underground product storage caverns and related
assets such as pipes and compressors.
(3)
Transportation
equipment includes vehicles and similar assets used in our
operations.
(4)
In
general, the estimated useful life of major components of this category
is: pipelines, 18-45 years (with some equipment at 5 years); office
furniture and equipment, 3-20 years; and buildings 20-35
years.
(5)
In
general, the estimated useful life of underground storage facilities is
20-35 years (with some components at 5 years).
|
||||||||||||
We reviewed assumptions underlying the
estimated remaining useful lives of certain of our assets during the first
quarter of 2008. As a result of our review, we increased the
remaining useful lives of certain assets, most notably the assets that
constitute our Texas Intrastate System as of January 1, 2008.
These
revisions extended the remaining useful life of such assets to incorporate
recent data showing that proved natural gas reserves supporting volumes for
these assets have increased their estimated useful life. There were
no changes to the residual values of these assets. These revisions
prospectively reduced our depreciation expense on assets having carrying values
totaling $2.72 billion at January 1, 2008. As a result of
this change in estimate, depreciation expense decreased by approximately $20.0
million for the year ended December 31, 2008. The reduction in
depreciation expense increased operating income and net income by equal amounts
from what they would have been absent the change. Depreciation
expense for the years ended December 31, 2009, 2008 and 2007 was $176.7 million,
$158.5 million and $163.4 million, respectively.
Asset
Retirement Obligations
We have recorded conditional AROs in
connection with certain right-of-way agreements, leases and regulatory
requirements. Conditional AROs are obligations in which the timing
and/or amount of settlement are uncertain. None of our assets are
legally restricted for purposes of settling AROs.
The
following table presents information regarding our AROs since December 31,
2007.
|
ARO
liability balance, December 31, 2007
|
$ | 8.1 | ||
|
Liabilities
incurred
|
1.3 | |||
|
Liabilities
settled
|
(5.3 | ) | ||
|
Accretion
expense
|
0.3 | |||
|
Revisions
in estimated cash flows
|
0.2 | |||
|
ARO
liability balance, December 31, 2008
|
$ | 4.6 | ||
|
Liabilities
settled
|
(0.7 | ) | ||
|
Accretion
expense
|
0.6 | |||
|
Revisions
in estimated cash flows
|
5.9 | |||
|
ARO
liability balance, December 31, 2009
|
$ | 10.4 |
The increase in our ARO liability
balance during 2009 primarily reflects revised estimates of the cost to comply
with regulatory abandonment obligations associated with our TPC Offshore
gathering system, a component of the Texas Intrastate System located offshore in
the Gulf of Mexico. Net property, plant and equipment at December 31,
2009 and 2008 includes $5.5 million and $1.1 million, respectively, of asset
retirement costs capitalized as an increase in the associated long-lived
asset.
The following table presents forecasted
accretion expense associated with our ARO’s for the years
presented:
|
2010
|
2011
|
2012
|
2013
|
2014
|
||||||||||||||
| $ | 0.7 | $ | 0.6 | $ | 0.6 | $ | 0.7 | $ | 0.8 | |||||||||
Acadian Gas, through a wholly owned
subsidiary, owns a collective 49.51% equity interest in Evangeline, which
consists of a 45% direct ownership interest in EGP and a 45.05% direct interest
in EGC. EGC also owns a 10% direct interest in EGP. Third
parties own the remaining equity interests in EGP and EGC. Acadian
Gas does not have a controlling interest in the Evangeline entities, but does
exercise significant influence on Evangeline’s operating
policies. Acadian Gas accounts for its financial investment in
Evangeline using the equity method. Our investment in Evangeline is
classified within our Natural Gas Pipelines & Services business
segment.
Evangeline owns a 27-mile natural gas
pipeline system extending from Taft, Louisiana to Westwego, Louisiana that
connects three electric generation stations owned by Entergy Louisiana
(“Entergy”). Evangeline’s most significant contract is a 21-year
natural gas sales agreement with Entergy. Evangeline is obligated to
make available-for-sale and deliver to Entergy certain specified
minimum
contract
quantities of natural gas on an hourly, daily, monthly and annual
basis. The sales contract provides for minimum annual quantities of
36.8 BBtus, until the contract expires on January 1,
2013.
In connection with the Entergy sales
contract, Evangeline has entered into a natural gas purchase contract with a
subsidiary of Acadian Gas that contains annual purchase
provisions. The pricing terms of the sales agreement with Entergy and
Evangeline’s purchase agreement with Acadian Gas are based on a weighted-average
cost of natural gas each month (subject to certain market index price ceilings
and incentive margins) plus a predetermined margin, creating an essentially
fixed monthly net sales margin.
In 1991, Evangeline entered into an
agreement with Entergy whereby Entergy was granted the right to acquire
Evangeline’s pipeline system for a nominal price, plus the assumption of all of
Evangeline’s obligations under the natural gas sales contract. The
option period begins the earlier of July 1, 2010 or upon the payment in
full of Evangeline’s Series B notes and terminates on December 31,
2012. We cannot ascertain when, or if, Entergy will exercise this
purchase option. This uncertainty results from various factors,
including decisions by Entergy’s management and regulatory approvals that may be
required for Entergy to acquire Evangeline’s assets.
We have received no distributions from
Evangeline since we acquired our interest in Evangeline in April
2001. The trust indenture governing Evangeline’s Series B notes
places restrictions on the payment of distributions to Evangeline’s
partners. Evangeline is permitted to pay distributions if, after giving
effect to the distribution, no default or event of default has occurred and is
continuing, funds held in its restricted cash account equals or exceeds its debt
service requirement and the holders of the Series B notes are cash
secured. Our share of undistributed earnings of Evangeline totaled
approximately $3.6 million at December 31, 2009. See Note 11 for a
description of Evangeline’s outstanding debt obligations.
Summarized
financial information of Evangeline is presented below.
|
At
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
BALANCE
SHEET DATA:
|
||||||||
|
Current
assets
|
$ | 24.4 | $ | 33.5 | ||||
|
Property,
plant and equipment, net
|
3.2 | 4.2 | ||||||
|
Other
assets
|
13.5 | 17.5 | ||||||
|
Total
assets
|
$ | 41.1 | $ | 55.2 | ||||
|
Current
liabilities
|
$ | 10.6 | $ | 24.2 | ||||
|
Other
liabilities
|
17.7 | 20.4 | ||||||
|
Consolidated
equity
|
12.8 | 10.6 | ||||||
|
Total
liabilities and consolidated equity
|
$ | 41.1 | $ | 55.2 | ||||
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
INCOME
STATEMENT DATA:
|
||||||||||||
|
Revenues
|
$ | 164.5 | $ | 371.8 | $ | 272.9 | ||||||
|
Operating
income
|
3.7 | 7.2 | 6.3 | |||||||||
|
Net
income
|
2.2 | 1.8 | 0.4 | |||||||||
The following table summarizes our
intangible asset balances by segment at the dates indicated:
|
At
December 31, 2009
|
At
December 31, 2008
|
|||||||||||||||||||||||
|
Gross
|
Accum.
|
Carrying
|
Gross
|
Accum.
|
Carrying
|
|||||||||||||||||||
|
Value
|
Amort.
|
Value
|
Value
|
Amort.
|
Value
|
|||||||||||||||||||
|
NGL
Pipelines & Services:
|
||||||||||||||||||||||||
|
Customer relationship intangibles
|
$ | 24.6 | $ | (8.9 | ) | $ | 15.7 | $ | 24.6 | $ | (6.4 | ) | $ | 18.2 | ||||||||||
|
Contract based intangibles
|
40.8 | (24.7 | ) | 16.1 | 40.8 | (20.1 | ) | 20.7 | ||||||||||||||||
|
Natural
Gas Pipelines & Services:
|
||||||||||||||||||||||||
|
Customer relationship intangibles
|
21.0 | (9.0 | ) | 12.0 | 21.0 | (7.6 | ) | 13.4 | ||||||||||||||||
|
Total all segments
|
$ | 86.4 | $ | (42.6 | ) | $ | 43.8 | $ | 86.4 | $ | (34.1 | ) | $ | 52.3 | ||||||||||
Due to the renewable nature of the
underlying contracts, we amortize the Mont Belvieu storage contracts on a
straight-line basis over the estimated 27 years of remaining economic life of
the storage assets to which they relate. The value assigned to the
Markham NGL storage contracts is being amortized to earnings over its estimated
2.3 years of remaining economic life, using the straight-line
method. The Mont Belvieu and Markham NGL storage contracts are
included in our NGL Pipelines & Services segment.
The values assigned to our customer
relationship intangible assets are being amortized to earnings using methods
that closely resemble the pattern in which the economic benefits of the
underlying natural resource basins from which the customers produce are
estimated to be consumed or otherwise used (based on proved
reserves). Our estimate of the useful life of each natural resource
basin is based on a number of factors, including third-party reserve estimates,
our view of the economic viability of production and exploration activities and
other industry factors.
The following table presents
amortization expense attributable to our intangible assets (by segment) for the
periods indicated:
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
NGL
Pipelines & Services
|
$ | 7.1 | $ | 7.6 | $ | 5.5 | ||||||
|
Natural
Gas Pipelines & Services
|
1.4 | 1.5 | 1.7 | |||||||||
|
Total segments
|
$ | 8.5 | $ | 9.1 | $ | 7.2 | ||||||
Based on information currently
available, the following table presents an estimate of future amortization
expense associated with our intangible assets at December 31, 2009:
|
For
the Year Ended December 31,
|
||||||||||||||||||||
|
2010
|
2011
|
2012
|
2013
|
2014
|
||||||||||||||||
|
NGL
Pipelines & Services
|
$ | 6.7 | $ | 6.4 | $ | 2.9 | $ | 1.7 | $ | 1.5 | ||||||||||
|
Natural
Gas Pipelines & Services
|
1.3 | 1.2 | 1.1 | 1.0 | 0.9 | |||||||||||||||
|
Total
segments
|
$ | 8.0 | $ | 7.6 | $ | 4.0 | $ | 2.7 | $ | 2.4 | ||||||||||
Goodwill
Goodwill represents the excess of the
purchase price of an acquired business over the amounts assigned to assets
acquired and liabilities assumed in the transaction. Goodwill is not
amortized; however, it is subject to annual impairment testing at the beginning
of each fiscal year. Our goodwill at December 31, 2009 and 2008 was
$4.9 million and represents an allocation to the DEP II Midstream Businesses of
the goodwill recorded by Enterprise Products Partners in connection with its
merger with a third-party partnership in September 2004. The carrying
value of our goodwill does not reflect any accumulated impairment
charges.
Our consolidated debt obligations
consisted of the following at the dates indicated:
|
At
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Revolving
Credit Facility, variable rate, due February 2011
|
$ | 175.0 | $ | 202.0 | ||||
|
Term
Loan Agreement, variable rate, due December 2011
|
282.3 | 282.3 | ||||||
|
Total
principal amount of long-term debt obligations
|
$ | 457.3 | $ | 484.3 | ||||
Revolving
Credit Facility
We have, in place, a $300.0 million
Revolving Credit Facility, all of which may be used for letters of credit, with
a $30.0 million sublimit for Swingline Loans. Letters of credit
outstanding under this facility reduce the amount available for
borrowings. We may make up to two requests for one-year extensions of
the maturity date (subject to certain restrictions).
At the closing of our initial public
offering, we made an initial draw of $200.0 million under this facility to fund
the $198.9 million cash distribution to EPO in connection with the DEP I drop
down transaction (see Note 1) and the remainder to pay debt issuance
costs. At December 31, 2009, the principal balance outstanding under
this facility was $175.0 million. After taking into account amounts
outstanding and the effect of the bankruptcy of one of the lenders, at December
31, 2009, we had the ability to borrow up to $121.7 million under our Revolving
Credit Facility. We have hedged a significant portion of our variable
interest rate exposure under this loan agreement; however, these hedges expire
in September 2010. See Note 6 for information regarding our interest
rate hedging activities.
We can increase the borrowing capacity
under our Revolving Credit Facility, without consent of the lenders, by an
amount not to exceed $150.0 million, by adding to the facility one or more
new lenders and/or requesting that the commitments of existing lenders be
increased.
As defined in the credit agreement,
variable interest rates charged under this facility may bear interest at either,
(i) a Eurodollar rate plus an applicable margin or (ii) a Base
Rate. The Base Rate is the higher of (i) the rate of interest
publicly announced by the administrative agent, Wachovia Bank, National
Association, as its Base Rate or (ii) 0.5% per annum above the Federal Funds
Rate in effect on such date.
The credit facility contains certain
financial and other customary affirmative and negative
covenants. Also, if an event of default exists under the credit
agreement, the lenders will be able to accelerate the maturity date of amounts
borrowed under the credit agreement and exercise other rights and
remedies.
Term
Loan Agreement
In April 2008, we entered into a
standby term loan agreement consisting of commitments for up to $300.0 million
under the Term Loan Agreement. Subsequently, commitments under the
Term Loan Agreement decreased to $282.3 million due to bankruptcy of one of the
lenders. On December 8, 2008, we borrowed the full amount available
under this loan agreement to fund the cash consideration due EPO in connection
with the DEP II drop down transaction (see Note 1).
We may prepay loans under the Term Loan
Agreement at any time, subject to prior notice in accordance with the credit
agreement. Loans may also be payable earlier in connection with an
event of default.
Loans under the Term Loan Agreement
bear interest of the type specified in the applicable borrowing request, and
consist of either Alternate Base Rate loans or Eurodollar loans. The
Term Loan Agreement contains certain financial and other customary affirmative
and negative covenants. Also, if an
event of
default exists under the credit agreement, the lenders will be able to
accelerate the maturity date of amounts borrowed under the credit agreement and
exercise other rights and remedies.
Covenants
We were in compliance with the
covenants of our debt agreements at December 31, 2009.
Information
Regarding Variable Interest Rates Paid
The following table presents the
weighted-average interest rate paid on our consolidated variable-rate debt
obligations during the year ended December 31, 2009.
|
Weighted-average
|
||||
|
interest
rate paid
|
||||
|
Revolving
Credit Facility, variable rate, due February 2011
|
1.4754% | |||
|
Term
Loan Agreement, variable rate, due December 2011
|
1.1486% | |||
Evangeline
Joint Venture Debt Obligation
The
following table presents the debt obligations of Evangeline at the dates
indicated:
|
At
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
9.9%
fixed interest rate senior secured notes due December 2010 (“Series B”
notes):
|
||||||||
|
Current
portion of debt – due December 31, 2010
|
$ | 3.2 | $ | 5.0 | ||||
|
Long-term
portion of debt
|
-- | 3.2 | ||||||
|
$7.5
million subordinated note payable to an affiliate of other
co-venture
|
||||||||
|
participant
(“LL&E Note”)
|
7.5 | 7.5 | ||||||
|
Total
joint venture debt principal obligation
|
$ | 10.7 | $ | 15.7 | ||||
The Series B notes are
collateralized by Evangeline’s: (i) property, plant and equipment;
(ii) proceeds from its Entergy natural gas sales contract (see Note 9); and
(iii) a debt service reserve requirement. Scheduled principal
repayments on the Series B notes are $5.0 million annually through
December 2009, with a final repayment in 2010 of approximately
$3.2 million. The trust indenture governing the Series B
notes contains certain financial and other customary affirmative and negative
covenants such as the maintenance of certain financial
ratios. Evangeline was in compliance with such covenants during the
year ended December 31, 2009.
The LL&E Note is subject to a
subordination agreement which prevents the repayment of principal and accrued
interest on the note until such time as the Series B note holders are
either fully cash secured through debt service accounts or have been completely
repaid. Variable rate interest accrues on the subordinated note at
LIBOR plus 0.5%. The weighted-average variable interest rates charged
on this note at December 31, 2009 and 2008 were 1.59% and 3.62%,
respectively. At December 31, 2009 and 2008, the amount of accrued
but unpaid interest on the LL&E Note was approximately $10.2 million and
$9.8 million, respectively.
Our common units represent limited
partner interests, which give the holders thereof the right to participate in
cash distributions and to exercise the other rights or privileges available to
them under our Amended and Restated Agreement of Limited Partnership (as amended
from time to time, the “Partnership Agreement”).
Capital accounts, as defined in our
Partnership Agreement, are maintained by us for our general partner and our
limited partners. The capital account provisions of our Partnership
Agreement incorporate
principles
established for U.S. Federal income tax purposes and are not comparable to the
equity accounts reflected under GAAP in our financial
statements. Earnings and cash distributions are allocated to our
partners in accordance with their respective percentage interests.
In February 2007, we completed our
initial public offering of 14,950,000 common units (including an overallotment
of 1,950,000 common units), which generated net cash proceeds of $290.5
million. As consideration for the DEP I drop down transaction (see
Note 1), we distributed $260.6 million of the net cash proceeds from our IPO
plus $198.9 million in borrowings and a net 5,351,571 common units to
EPO. We used $38.5 million of the overallotment proceeds to redeem
1,950,000 of the 7,301,571 common units we originally issued to EPO in
connection with the DEP I drop down transaction, resulting in a final amount of
5,351,571 common units beneficially owned by EPO.
Class
B Units
Our limited partners’ equity account
balance at December 31, 2008 reflected the issuance to EPO of 37,333,887 Class B
units, which were used along with proceeds borrowed under the Term Loan
Agreement to acquire the DEP II Midstream Businesses in December
2008. In February 2009, the Class B units were converted on a
one-to-one basis into common units.
Registration
Statements and Equity Offerings
We have a universal shelf registration
statement on file with the SEC that allows us to issue up to $1 billion in debt
and equity securities for general partnership purposes. After taking
into account a June 2009 equity offering made under this registration statement
(see below), we can issue approximately $856.4 million of additional securities
under this registration statement in the future.
In June 2009, we issued 8,000,000
common units to the public at an offering price of $16.00 per
unit. We granted the underwriters of this offering a 30-day option to
purchase up to 1,200,000 additional common units to cover over-allotments, which
they exercised for 943,400 common units in July 2009. We generated
net cash proceeds of approximately $137.4 million from this underwritten equity
offering. The net proceeds were used to repurchase an equal number of
our common units beneficially owned by EPO. The repurchased common
units were subsequently cancelled.
In December 2009, we filed a
registration statement with the SEC authorizing the issuance of up to an
aggregate 2,000,000 common units in connection with a distribution reinvestment
plan (“DRIP”). The DRIP gives unitholders of record and beneficial
owners of our common units the ability to increase the number of our common
units they own through voluntarily reinvesting their quarterly cash
distributions into the purchase of additional common units. Plan participants
may purchase our common units at a discount ranging from 0% to 5% (currently set
at 5%), which will be set from time to time by us. We did not issue
any common units under the DRIP during the year ended December 31,
2009.
In
February 2010, we filed a registration statement with the SEC authorizing the
issuance of up to 1,000,000 common units in connection with an employee unit
purchase plan and a long-term incentive plan. These plans became
effective on February 11, 2010. See Note 5 for additional
information.
Unit
History
The following table details changes in
our outstanding common units since our initial public offering on February 5,
2007:
|
Limited
|
Total
|
|||||||||||
|
Partner
|
Treasury
|
Outstanding
|
||||||||||
|
Units
|
Units
|
Units
|
||||||||||
|
Activity
on February 5, 2007:
|
||||||||||||
|
Common
units originally issued to EPO in connection with the DEP I drop down
transaction
|
7,301,571 | -- | 7,301,571 | |||||||||
|
Common
units issued in connection with our IPO
|
14,950,000 | -- | 14,950,000 | |||||||||
|
Redemption
of common units using proceeds from IPO overallotment
|
(1,950,000 | ) | -- | (1,950,000 | ) | |||||||
|
Common
units outstanding, December 31, 2007
|
20,301,571 | -- | 20,301,571 | |||||||||
|
Common
units sold to EPO in connection with the DEP II drop down
transaction
|
41,529 | -- | 41,529 | |||||||||
|
Common
units outstanding, December 31, 2008
|
20,343,100 | -- | 20,343,100 | |||||||||
|
Conversion
of Class B units to common units on February 1, 2009
|
37,333,887 | -- | 37,333,887 | |||||||||
|
June
2009 underwritten offering
|
8,000,000 | -- | 8,000,000 | |||||||||
|
Acquisition
of common units from EPO in June 2009
|
(8,000,000 | ) | 8,000,000 | -- | ||||||||
|
Cancellation
of treasury units in June 2009
|
-- | (8,000,000 | ) | (8,000,000 | ) | |||||||
|
Additional
units issued in July 2009 in connection with
|
||||||||||||
|
June
2009 underwritten offering
|
943,400 | -- | 943,400 | |||||||||
|
Acquisition
of common units from EPO in July 2009
|
(943,400 | ) | 943,400 | -- | ||||||||
|
Cancellation
of treasury units in July 2009
|
-- | (943,400 | ) | (943,400 | ) | |||||||
|
Common
units outstanding, December 31, 2009
|
57,676,987 | -- | 57,676,987 | |||||||||
Distributions
Our partnership agreement requires us
to distribute all of our available cash (as defined in our Partnership
Agreement) to our partners on a quarterly basis. Such distributions
are not cumulative. In addition, we do not have a legal obligation to
pay distributions at our initial distribution rate or at any other
rate. Our general partner has no incentive distribution
rights. The following table presents the amount, record date and
payment date of the quarterly cash distributions we paid on each of our common
units with respect to each quarterly period since our IPO.
|
Cash
Distribution History
|
||||||
|
Per
|
Record
|
Payment
|
||||
|
Unit
|
Date
|
Date
|
||||
|
2008
|
||||||
|
1st
Quarter
|
0.4100 |
April
30, 2008
|
May
7, 2008
|
|||
|
2nd
Quarter
|
0.4200 |
July
31, 2008
|
August
7, 2008
|
|||
|
3rd
Quarter
|
0.4200 |
October
31, 2008
|
November
12, 2008
|
|||
|
4th Quarter (1)
|
0.4275 |
January
30, 2009
|
February
9, 2009
|
|||
|
2009
|
||||||
|
1st
Quarter
|
0.4300 |
April
30, 2009
|
May
8, 2009
|
|||
|
2nd
Quarter
|
0.4350 |
July
31, 2009
|
August
7, 2009
|
|||
|
3rd
Quarter
|
0.4400 |
October
30, 2009
|
November
5, 2009
|
|||
|
4th
Quarter
|
0.4450 |
January
29, 2010
|
February
5, 2010
|
|||
|
(1)
We
issued 37.3 million Class B units in connection with the DEP II drop
down. The Class B units received a cash distribution of $0.1115 per
unit for the distribution that Duncan Energy Partners paid with respect to
the fourth quarter of 2008, which represented the regular quarterly
distribution pro-rated for the 24-day period from December 8, 2008, the
closing date of the DEP II drop down transaction, to December 31,
2008. These units automatically converted on a one-for-one basis to
common units on February 1, 2009.
|
||||||
Accumulated
Other Comprehensive Loss
Our AOCI balance, which was related to
interest rate derivative instruments, reflected losses of $5.4 million and $9.6
million at December 31, 2009 and December 31, 2008,
respectively.
We account for EPO’s retained ownership
interests in each of the DEP I and DEP II Midstream Businesses as a
noncontrolling interest. Under this method of presentation, all revenues
and expenses of these businesses are included in consolidated net income and
EPO’s share (as Parent) of the income of these businesses is deducted from
consolidated net income to derive net income attributable to Duncan Energy
Partners L.P. EPO’s share of the net assets of the DEP I and DEP II
Midstream Businesses is presented as noncontrolling interest in subsidiaries (a
component of equity) on our Consolidated Balance Sheets.
DEP
I Midstream Businesses – Parent
The DEP I Midstream Businesses allocate
their net income (or loss) to us and EPO based on our respective sharing ratios,
which are currently 66% to us and 34% to EPO. In deriving the net
income (or loss) of Mont Belvieu Caverns to be allocated between us and EPO,
certain special allocations are required as follows:
|
§
|
EPO
is allocated all operational measurement gains and losses;
and
|
|
§
|
EPO
is allocated 100% of the depreciation expense related to capital projects
that it has fully funded.
|
Distributions paid to us and EPO by the
DEP I Midstream Businesses are in accordance with each owner’s respective
sharing ratio. In general, contributions made by us and EPO to the
DEP I Midstream Businesses are in accordance with the previously noted sharing
ratios. However, special funding arrangements exist under the terms of an
Omnibus Agreement and the limited liability company agreement of Mont Belvieu
Caverns (the “Caverns LLC Agreement”). See Note 15 for additional
information regarding these related party agreements.
In accordance with the Omnibus
Agreement, EPO agreed to fund all of the capital expenditures incurred by South
Texas NGL and Mont Belvieu Caverns with respect to certain expansion projects
that were underway at the time of our initial public offering in February
2007. EPO made aggregate cash contributions to South Texas NGL and Mont
Belvieu Caverns of $1.4 million and $32.5 million in connection with these
capital projects during the years ended December 31, 2009 and 2008,
respectively. The majority of these contributions related to funding Phase
II expansion costs of the South Texas NGL pipeline. This project was
completed in 2008. EPO will not receive an increased allocation of income
or cash distributions as a result of these contributions to South Texas NGL and
Mont Belvieu Caverns.
EPO made cash contributions of $16.6
million and $99.5 million under the Caverns LLC Agreement during the years ended
December 31, 2009 and 2008, respectively, to fund 100% of certain
storage-related projects sponsored by EPO’s NGL marketing activities. We
elected to not participate in such projects. EPO is not expected to
receive an increased allocation of earnings or cash flows as a result of these
contributions to Mont Belvieu Caverns. Additional contributions of
approximately $32.7 million are expected from EPO to fund such projects in
2010. The constructed assets will be the property of Mont Belvieu
Caverns.
In accordance with the Caverns LLC
Agreement, EPO is required each period to contribute cash to Mont Belvieu
Caverns for net operational measurement losses and is entitled to receive
distributions from Mont Belvieu Caverns for net operational measurement
gains. We continue to record operational measurement gains and losses
associated with our Mont Belvieu storage complex. Such amounts are
included in operating costs and expenses and gross operating margin.
However, these operational measurement gains and losses do not impact net income
attributable to Duncan Energy Partners since they are allocated to EPO. We
have not established a reserve for operational measurement losses on our balance
sheet.
The
following table presents our calculation of “Net income attributable to
noncontrolling interest – DEP I Midstream Businesses – Parent” for the years
ended December 31, 2009, 2008 and 2007.
|
For
the Year Ended
|
||||||||||||
|
December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Total
net income of DEP I Midstream Businesses, prior to special
allocations
|
$ | 68.0 | $ | 56.4 | $ | 45.4 | ||||||
|
Multiplied
by Parent 34% interest in net income
|
x 34 | % | x 34 | % | x 34 | % | ||||||
|
Parent
34% interest in net income, prior to special allocations
|
23.1 | 19.2 | 15.5 | |||||||||
|
Add
(deduct) operational measurement gain (loss) allocated to
Parent
|
(1.7 | ) | (6.8 | ) | 4.5 | |||||||
|
Less
depreciation expense related to fully funded projects allocated to
Parent
|
(6.1 | ) | (1.0 | ) | -- | |||||||
|
Net
income attributable to noncontrolling interest – DEP I Midstream
Businesses – Parent
|
$ | 15.3 | $ | 11.4 | $ | 20.0 | ||||||
The following table provides a
reconciliation of the amounts presented as “Noncontrolling interest in
subsidiaries – DEP I Midstream Businesses – Parent” on our consolidated balance
sheets at December 31, 2009 and 2008:
|
December
31, 2007 balance
|
$ | 355.2 | ||
|
Net income attributable to noncontrolling interest – DEP I Midstream
Businesses – Parent
|
11.4 | |||
|
Contributions made by EPO to South Texas NGL and Mont Belvieu
Caverns
in
connection with the following agreements:
|
||||
|
Caverns
LLC Agreement
|
88.1 | |||
|
Omnibus Agreement
|
31.4 | |||
|
Other contributions made by EPO to the DEP I Midstream
Businesses
|
36.5 | |||
|
Cash distributions paid to EPO by the DEP I Midstream
Businesses
|
(44.2 | ) | ||
|
December
31, 2008 balance
|
478.4 | |||
|
Net income attributable to noncontrolling interest – DEP I Midstream
Businesses – Parent
|
15.3 | |||
|
Contributions made by EPO to South Texas NGL and Mont Belvieu
Caverns
in connection with the following agreements:
|
||||
|
Caverns LLC Agreement
|
16.6 | |||
|
Omnibus Agreement
|
1.4 | |||
|
Other contributions made by EPO to the DEP I Midstream
Businesses
|
0.9 | |||
|
Cash distributions paid to EPO by the DEP I Midstream
Businesses
|
(25.3 | ) | ||
|
December
31, 2009 balance
|
$ | 487.3 |
DEP
II Midstream Businesses – Parent
At the time of the DEP II drop down
transaction, the total estimated fair value of the DEP II Midstream Businesses
was approximately $3.2 billion. The total value of the consideration
we provided to EPO in the DEP II drop down transaction was $730.0 million and
represented, at the time of the transaction, the acquisition of 22.6% of the
equity of the DEP II Midstream Businesses. EPO retained the remaining
77.4% of equity. The 22.6% and 77.4% amounts are referred to as the
“Percentage Interests,” and represent each owner’s initial relative economic
investment in the DEP II Midstream Businesses at December 8, 2008.
Generally, to the extent that the DEP
II Midstream Businesses collectively generate cash sufficient to pay
distributions to EPO and us, such cash will be distributed first to us (the
“Tier I distribution,” based on our $730.0 million aggregate investment) and
then to EPO (the “Tier II distribution”), in amounts sufficient to generate an
annualized return to both owners based on their respective
investments. Distributions in excess of these amounts (the “Tier III
distributions”) will be distributed 98% to EPO and 2% to
us.
The initial annualized return rate for
2009 was 11.85%, and was determined by EPO and us based on our estimated
weighted-average cost of capital at December 8, 2008, plus 1.0%. The
annualized return rate increases by 2.0% on January 1 of each
year. As a result, the annualized return rate for 2010 will be
12.087%. If we participate in an expansion capital project involving
the DEP II Midstream Businesses, we
may
request an incremental adjustment to the then-applicable annualized return rate
to reflect our weighted-average cost of capital associated with such
contribution.
The annualized return rate is applied
to each party’s aggregate investment (or “Distribution Base”) in the DEP II
Midstream Businesses. To the extent that we and/or EPO make capital
contributions to fund expansion capital projects involving the DEP II Midstream
Businesses, the Distribution Base of the contributing member will be increased
by that member’s capital contribution at the time such contribution is
made. At December 8, 2008 and December 31, 2009, our Distribution
Base was $730.0 million. EPO’s Distribution Base was $452.1 million
and $817.9 million at December 8, 2008 and December 31, 2009,
respectively. The increase in EPO’s Distribution Base is the result
of its decision to fund 100% of the expansion capital projects of the DEP II
Midstream Businesses since December 8, 2008. We have not yet
participated in the expansion capital project spending of the DEP II Midstream
Businesses, although we may elect to invest in existing or future expansion
projects at a later date.
Net income (or loss) of the DEP II
Midstream Businesses is first allocated to us and EPO based on each entity’s
Percentage Interest of 22.6% and 77.4%, respectively, and then in a manner that
in part follows the cash distributions paid by (or contributions made to) each
DEP II Midstream Business. Under our income sharing arrangement with
EPO, we are allocated additional income (in excess of our Percentage Interest)
to the extent that the cash distributions we receive (or contributions made)
exceed the amount we would have been entitled to receive (or required to fund)
based solely on our Percentage Interest. This additional earnings
allocation to us reduces the amount of income allocated to EPO by an equal
amount and may result in EPO being allocated a loss when we are allocated
income. It is our expectation that EPO will be allocated a loss by
the DEP II Midstream Businesses until such time as expansion capital projects
such as the Sherman Extension and Trinity River Lateral realize their income and
cash flow potential. Our participation in the expected future
increase in cash flow from such projects is limited (beyond our annualized
return amount) to 2% of such upside, with EPO receiving 98% of the
benefit.
The following table presents the
allocation of net income of the DEP II Midstream Businesses for the 24-day
period extending from December 8, 2008 to December 31, 2008.
|
DEP
|
EPO
|
|||||||||||
|
Total
net income of DEP II Midstream Businesses
|
$ | 0.5 | $ | 0.5 | ||||||||
|
Multiplied
by each owner's Percentage Interest
|
22.6 | % | 77.4 | % | ||||||||
|
Base
earnings allocation to each owner
|
0.1 | 0.4 | ||||||||||
|
Additional
earnings allocation to Duncan Energy Partners:
|
||||||||||||
|
Total
distributions paid by the DEP II Midstream Businesses with
respect to period
|
$ | 5.4 | ||||||||||
|
Multiplied
by 22.6% Percentage Interest of Duncan Energy Partners
|
22.6 | % | ||||||||||
|
Duncan
Energy Partners’ Percentage Interest in the total cash
distributions
|
||||||||||||
|
paid
by the DEP II Midstream Businesses with respect to period
|
1.2 | |||||||||||
|
Less
actual distributions paid to Duncan Energy Partners
|
||||||||||||
|
with
respect to period based on annualized return for period
|
5.6 | 4.4 | (4.4 | ) | ||||||||
|
Net
income attributable to Duncan Energy Partners
|
$ | 4.5 | ||||||||||
|
Net
loss attributable to EPO as noncontrolling interest
|
$ | (4.0 | ) | |||||||||
The following table presents the
allocation of net income of the DEP II Midstream Businesses for the year ended
December 31, 2009:
|
DEP
|
EPO
|
|||||||||||
|
Total
net loss of DEP II Midstream Businesses
|
$ | (0.5 | ) | $ | (0.5 | ) | ||||||
|
Multiplied
by each owner's Percentage Interest
|
22.6 | % | 77.4 | % | ||||||||
|
Base
earnings allocation to each owner
|
(0.1 | ) | (0.4 | ) | ||||||||
|
Additional
earnings allocation to Duncan Energy Partners:
|
||||||||||||
|
Total
distributions paid by the DEP II Midstream Businesses with
respect to period
|
$ | 116.3 | ||||||||||
|
Multiplied
by 22.6% Percentage Interest of Duncan Energy Partners
|
22.6 | % | ||||||||||
|
Duncan
Energy Partners’ Percentage Interest in the total cash
distributions
|
||||||||||||
|
paid
by the DEP II Midstream Businesses with respect to period
|
26.3 | |||||||||||
|
Less
actual distributions paid to Duncan Energy Partners
|
||||||||||||
|
with
respect to period based on annualized return for period
|
86.5 | 60.2 | (60.2 | ) | ||||||||
|
Net
income attributable to Duncan Energy Partners
|
$ | 60.1 | ||||||||||
|
Net
loss attributable to EPO as noncontrolling interest
|
$ | (60.6 | ) | |||||||||
We and EPO received $86.5 million and
$29.8 million, respectively, in cash distributions from the DEP II Midstream
Businesses for the twelve months ended December 31, 2009. The $86.5
million (or, approximately, $21.6 million each quarter) received by us with
respect to 2009 represents the annualized return rate for 2009 of 11.85%
multiplied by our Distribution Base of $730.0 million. As a result,
we received our expected Tier I distributions for the period. Based
on EPO’s Distribution Base throughout 2009, it was entitled to $83.4 million of
Tier II distributions, of which it received only $29.8 million. No
Tier III distributions were paid by the DEP II Midstream Businesses with respect
to 2009.
The following table provides a
reconciliation of the amounts presented as “Noncontrolling interest in
subsidiaries – DEP II Midstream Businesses – Parent” on our Consolidated Balance
Sheets at December 31, 2009 and 2008. Amounts are for the period from
the closing of the drop down transaction to December 31, 2009.
|
Retention
by Parent of ownership interest in DEP II Midstream Businesses on December
8, 2008
|
$ | 2,595.5 | ||
|
Net
loss attributable to noncontrolling interest – DEP II Midstream Businesses
– Parent
|
(4.0 | ) | ||
|
Contributions
by EPO in connection with expansion cash calls
|
21.3 | |||
|
Distributions
to noncontrolling interest of subsidiary operating cash
flows
|
(0.8 | ) | ||
|
Other
general cash contributions from noncontrolling interest
|
1.0 | |||
|
December
31, 2008 balance
|
$ | 2,613.0 | ||
|
Allocated
loss from DEP II Midstream Businesses to EPO as Parent
|
(60.6 | ) | ||
|
Contributions
by EPO in connection with expansion cash calls
|
344.5 | |||
|
Distributions
to noncontrolling interest of subsidiary operating cash
flows
|
(31.8 | ) | ||
|
Other
general cash contributions from noncontrolling interest
|
23.1 | |||
|
December
31, 2009 balance
|
$ | 2,888.2 |
For additional information regarding
our agreements with EPO in connection with the DEP II drop down transaction, see
“Significant Relationships and Agreements with EPO – Company and Limited
Partnership Agreements – DEP II Midstream Businesses” under Note
15.
We have three reportable business
segments: (i) Natural Gas Pipelines & Services; (ii) NGL Pipelines &
Services and (iii) Petrochemical Services. Our business segments are
generally organized and managed according to the type of services rendered (or
technologies employed) and products produced and/or sold.
We evaluate segment performance based
on the non-GAAP financial measure of gross operating margin. Gross
operating margin (either in total or by individual segment) is an important
performance measure of the core profitability of our operations. This
measure forms the basis of our internal financial reporting and is used by
management in deciding how to allocate capital resources among
business
segments. We
believe that investors benefit from having access to the same financial measures
that management uses in evaluating segment results. The GAAP
financial measure most directly comparable to total segment gross operating
margin is operating income.
We define total segment gross operating
margin as operating income before: (i) depreciation, amortization and
accretion expense; (ii) non-cash consolidated asset impairment charges;
(iii) gains and losses from asset sales and related transactions and
(iv) general and administrative costs. Gross operating margin by
segment is calculated by subtracting segment operating costs and expenses (net
of the adjustments noted above) from segment revenues, with both segment totals
before the elimination of any intersegment and intrasegment
transactions. In accordance with GAAP, intercompany accounts and
transactions are eliminated in consolidation. Gross operating margin
is exclusive of other income and expense transactions, provision for income
taxes, extraordinary charges and the cumulative effect of changes in accounting
principles. Gross operating margin is presented on a 100% basis
before the allocation of earnings to noncontrolling interests.
Segment revenues include intersegment
and intrasegment transactions. Our consolidated revenues reflect the
elimination of all material intercompany transactions.
We include
equity earnings from Evangeline in our measurement of segment gross operating
margin and operating income. Our equity investments in midstream
energy operations such as those conducted by Evangeline are a vital component of
our long-term business strategy and important to the operations of Acadian
Gas. This method of operation enables us to achieve favorable
economies of scale relative to our level of investment and also lowers our
exposure to business risks compared to the profile we would have on a
stand-alone basis. Our equity investee is within the same industry as
our consolidated operations, thus we believe treatment of earnings from our
equity method investee as a component of gross operating margin and operating
income is appropriate.
Segment assets consist of property,
plant and equipment, our investment in Evangeline, intangible assets and
goodwill. The carrying values of such amounts are assigned to each
segment based on each asset’s or investment’s principal operations and
contribution to the gross operating margin of that particular
segment. Since construction-in-progress amounts (which are a
component of property, plant and equipment) generally do not contribute to
segment gross operating margin, such amounts are excluded from segment asset
totals until they are placed in service. Consolidated intangible
assets and goodwill are assigned to each segment based on the classification of
the assets to which they relate.
The following table shows our
measurement of total segment gross operating margin for the periods
indicated:
|
For
the Year Ended December 31,
|
|||||||||||||
|
2009
|
2008
|
2007
|
|||||||||||
|
Revenues
|
$ | 979.3 | $ | 1,598.1 | $ | 1,220.3 | |||||||
|
Less:
|
Operating
costs and expenses
|
(908.3 | ) | (1,512.8 | ) | (1,171.0 | ) | ||||||
|
Add:
|
Equity
in income of Evangeline
|
1.1 | 0.9 | 0.2 | |||||||||
|
Depreciation,
amortization and accretion in
|
|||||||||||||
|
operating
costs and expenses (1)
|
186.3 | 167.3 | 175.3 | ||||||||||
|
Impairment
charge included in operating
|
|||||||||||||
|
costs
and expenses
|
4.2 | -- | -- | ||||||||||
|
Gain
on asset sales and related transactions
|
|||||||||||||
|
in
operating costs and expenses
|
(0.5 | ) | (0.5 | ) | (0.1 | ) | |||||||
|
Total
segment gross operating margin
|
$ | 262.1 | $ | 253.0 | $ | 224.7 | |||||||
|
(1)
Amount
is a component of “Depreciation, amortization and accretion” as presented
on the Statements of Consolidated Cash Flows.
|
|||||||||||||
The
following table presents a reconciliation of total segment gross operating
margin to operating income and further to GAAP net income for the periods
noted:
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Total
segment gross operating margin
|
$ | 262.1 | $ | 253.0 | $ | 224.7 | ||||||
|
Adjustments
to reconcile total segment gross operating margin
|
||||||||||||
|
to
operating income:
|
||||||||||||
|
Depreciation,
amortization and accretion in
|
||||||||||||
|
operating
costs and expenses (1)
|
(186.3 | ) | (167.3 | ) | (175.3 | ) | ||||||
|
Impairment
charge included in operating
|
||||||||||||
|
costs
and expenses
|
(4.2 | ) | -- | -- | ||||||||
|
Gain
on asset sales and related transactions in
|
||||||||||||
|
operating
costs and expenses
|
0.5 | 0.5 | 0.1 | |||||||||
|
General
and administrative costs
|
(11.2 | ) | (18.3 | ) | (13.1 | ) | ||||||
|
GAAP
operating income
|
60.9 | 67.9 | 36.4 | |||||||||
|
Other
expense, net
|
(13.8 | ) | (11.5 | ) | (8.6 | ) | ||||||
|
Provision
for income taxes
|
(1.3 | ) | (1.1 | ) | (4.2 | ) | ||||||
|
GAAP
net income
|
$ | 45.8 | $ | 55.3 | $ | 23.6 | ||||||
|
(1) Amount
is a component of “Depreciation, amortization and accretion” as presented
on the Statements of Consolidated Cash Flows.
|
||||||||||||
Information by segment, together with
reconciliations to our consolidated totals, is presented in the following
table:
|
Natural
Gas
|
NGL
|
Adjustments
|
||||||||||||||||||
|
Pipelines
|
Pipelines
|
Petrochemical
|
and
|
Consolidated
|
||||||||||||||||
|
&
Services
|
&
Services
|
Services
|
Eliminations
|
Totals
|
||||||||||||||||
|
Revenues
from third parties:
|
||||||||||||||||||||
|
Year
ended December 31, 2009
|
$ | 390.2 | $ | 88.2 | $ | 13.6 | $ | -- | $ | 492.0 | ||||||||||
|
Year
ended December 31, 2008
|
773.1 | 69.1 | 14.2 | -- | 856.4 | |||||||||||||||
|
Year
ended December 31, 2007
|
685.2 | 59.7 | 14.4 | -- | 759.3 | |||||||||||||||
|
Revenues
from related parties:
|
||||||||||||||||||||
|
Year
ended December 31, 2009
|
348.5 | 138.8 | -- | -- | 487.3 | |||||||||||||||
|
Year
ended December 31, 2008
|
582.2 | 159.5 | -- | -- | 741.7 | |||||||||||||||
|
Year
ended December 31, 2007
|
323.2 | 134.8 | 3.0 | -- | 461.0 | |||||||||||||||
|
Total
revenues:
|
||||||||||||||||||||
|
Year
ended December 31, 2009
|
738.7 | 227.0 | 13.6 | -- | 979.3 | |||||||||||||||
|
Year
ended December 31, 2008
|
1,355.3 | 228.6 | 14.2 | -- | 1,598.1 | |||||||||||||||
|
Year
ended December 31, 2007
|
1,008.4 | 194.5 | 17.4 | -- | 1,220.3 | |||||||||||||||
|
Equity
in income of Evangeline:
|
||||||||||||||||||||
|
Year
ended December 31, 2009
|
1.1 | -- | -- | -- | 1.1 | |||||||||||||||
|
Year
ended December 31, 2008
|
0.9 | -- | -- | -- | 0.9 | |||||||||||||||
|
Year
ended December 31, 2007
|
0.2 | -- | -- | -- | 0.2 | |||||||||||||||
|
Gross
operating margin by individual
|
||||||||||||||||||||
|
business
segment and in total:
|
||||||||||||||||||||
|
Year
ended December 31, 2009
|
148.2 | 103.4 | 10.5 | -- | 262.1 | |||||||||||||||
|
Year
ended December 31, 2008
|
159.0 | 82.9 | 11.1 | -- | 253.0 | |||||||||||||||
|
Year
ended December 31, 2007
|
122.5 | 87.9 | 14.3 | -- | 224.7 | |||||||||||||||
|
Segment
assets:
|
||||||||||||||||||||
|
At
December 31, 2009
|
3,340.8 | 946.1 | 83.3 | 233.7 | 4,603.9 | |||||||||||||||
|
At
December 31, 2008
|
2,909.8 | 936.5 | 86.6 | 459.0 | 4,391.9 | |||||||||||||||
|
At
December 31, 2007
|
2,716.6 | 731.5 | 89.6 | 257.3 | 3,795.0 | |||||||||||||||
|
Property,
plant and equipment:
|
||||||||||||||||||||
|
At
December 31, 2009
|
3,318.8 | 913.8 | 83.3 | 233.7 | 4,549.6 | |||||||||||||||
|
At
December 31, 2008
|
2,887.5 | 897.1 | 86.6 | 459.0 | 4,330.2 | |||||||||||||||
|
At
December 31, 2007
|
2,693.8 | 697.3 | 89.6 | 257.3 | 3,738.0 | |||||||||||||||
|
Investment in Evangeline:
(see Note 9)
|
||||||||||||||||||||
|
At
December 31, 2009
|
5.6 | -- | -- | -- | 5.6 | |||||||||||||||
|
At
December 31, 2008
|
4.5 | -- | -- | -- | 4.5 | |||||||||||||||
|
At
December 31, 2007
|
3.5 | -- | -- | -- | 3.5 | |||||||||||||||
|
Intangible
assets:
|
||||||||||||||||||||
|
At
December 31, 2009
|
12.0 | 31.8 | -- | -- | 43.8 | |||||||||||||||
|
At
December 31, 2008
|
13.4 | 38.9 | -- | -- | 52.3 | |||||||||||||||
|
At
December 31, 2007
|
14.9 | 33.7 | -- | -- | 48.6 | |||||||||||||||
|
Goodwill:
|
||||||||||||||||||||
|
At
December 31, 2009
|
4.4 | 0.5 | -- | -- | 4.9 | |||||||||||||||
|
At
December 31, 2008
|
4.4 | 0.5 | -- | -- | 4.9 | |||||||||||||||
|
At
December 31, 2007
|
4.4 | 0.5 | -- | -- | 4.9 | |||||||||||||||
Our
consolidated revenues were earned in the United States. Our
operations are located in Texas and Louisiana. Our largest
third-party customer was Exxon Mobil, which accounted for 7.5%, 10.0% and 7.6%
of our consolidated revenues in 2009, 2008 and 2007,
respectively. The majority of our revenues from Exxon Mobil is
derived from the sale and transportation of natural gas and is also presented in
our Natural Gas Pipelines & Services business segment. Sales to
Exxon Mobil totaled $73.4 million, $159.2 million and $93.2 million for the
years ended December 31, 2009, 2008 and 2007, respectively.
The following table provides additional
information regarding our consolidated revenues (net of adjustments and
eliminations) and expenses for the periods noted:
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Natural
Gas Pipelines & Services:
|
||||||||||||
|
Sales
of natural gas
|
$ | 460.2 | $ | 1,100.2 | $ | 794.1 | ||||||
|
Natural
gas transportation services
|
263.2 | 246.7 | 212.8 | |||||||||
|
Natural
gas storage services
|
15.3 | 8.4 | 1.5 | |||||||||
|
Total
|
$ | 738.7 | $ | 1,355.3 | $ | 1,008.4 | ||||||
|
NGL
Pipelines & Services:
|
||||||||||||
|
Sales
of NGLs
|
$ | 35.0 | $ | 47.9 | $ | 40.3 | ||||||
|
Sales
of other products
|
11.3 | 15.0 | 10.8 | |||||||||
|
NGL
and petrochemical storage services
|
104.9 | 87.4 | 68.9 | |||||||||
|
NGL
fractionation services
|
29.5 | 32.4 | 30.3 | |||||||||
|
NGL
transportation services
|
43.8 | 43.6 | 42.5 | |||||||||
|
Other
services
|
2.5 | 2.3 | 1.7 | |||||||||
|
Total
|
$ | 227.0 | $ | 228.6 | $ | 194.5 | ||||||
|
Petrochemical
Services:
|
||||||||||||
|
Propylene
transportation services
|
$ | 13.6 | $ | 14.2 | $ | 17.4 | ||||||
|
Total
consolidated revenues
|
$ | 979.3 | $ | 1,598.1 | $ | 1,220.3 | ||||||
|
Consolidated
cost and expenses
|
||||||||||||
|
Operating
costs and expenses:
|
||||||||||||
|
Cost
of natural gas and NGL sales
|
$ | 479.7 | $ | 1,123.9 | $ | 815.8 | ||||||
|
Depreciation,
amortization and accretion
|
186.3 | 167.4 | 175.3 | |||||||||
|
Gain
on asset sales and
|
||||||||||||
|
related
transactions
|
(0.5 | ) | (0.5 | ) | (0.1 | ) | ||||||
|
Other
operating expenses
|
242.8 | 222.0 | 180.0 | |||||||||
|
General
and administrative costs
|
11.2 | 18.3 | 13.1 | |||||||||
|
Total
consolidated costs and expenses
|
$ | 919.5 | $ | 1,531.1 | $ | 1,184.1 | ||||||
Changes in our revenues and operating
costs and expenses year-to-year are explained in part by changes in energy
commodity prices. In general, higher energy commodity prices result
in an increase in our revenues attributable to the sale of natural gas and NGLs;
however, these higher commodity prices also increase the associated cost of
sales as purchase prices rise.
The
following table summarizes our related party transactions for the periods
indicated:
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Revenues:
|
||||||||||||
|
Revenues
from EPO:
|
||||||||||||
|
Sales
of natural gas
|
$ | 141.9 | $ | 177.3 | $ | 29.6 | ||||||
|
Natural
gas transportation services
|
56.4 | 51.5 | 35.8 | |||||||||
|
Natural
gas storage services
|
2.6 | 0.9 | -- | |||||||||
|
Sales
of NGLs
|
33.7 | 52.9 | 41.2 | |||||||||
|
NGL
and petrochemical storage services
|
36.2 | 35.2 | 28.9 | |||||||||
|
NGL
fractionation services
|
32.0 | 29.7 | 30.3 | |||||||||
|
NGL
transportation services
|
28.6 | 30.4 | 27.6 | |||||||||
|
Other services
|
-- | -- | 3.0 | |||||||||
|
Sales
of natural gas – Evangeline
|
155.5 | 362.9 | 264.2 | |||||||||
|
Natural
gas transportation services – Energy Transfer Equity
|
0.1 | 0.9 | 0.4 | |||||||||
|
NGL
and petrochemical storage services – Energy Transfer
Equity
|
0.3 | -- | -- | |||||||||
|
Total
related party revenues
|
$ | 487.3 | $ | 741.7 | $ | 461.0 | ||||||
|
Operating
costs and expenses:
|
||||||||||||
|
EPCO
administrative services agreement
|
$ | 85.8 | $ | 72.1 | $ | 63.7 | ||||||
|
Expenses
with EPO:
|
||||||||||||
|
Purchases
of natural gas
|
52.1 | 229.9 | 29.1 | |||||||||
|
Operational
measurement losses (gains)
|
1.7 | 6.8 | (4.5 | ) | ||||||||
|
Other
expenses with EPO
|
16.4 | 18.4 | 7.4 | |||||||||
|
Purchases
of natural gas – Nautilus
|
1.7 | 10.3 | 3.5 | |||||||||
|
Expenses
with Energy Transfer Equity:
|
||||||||||||
|
Purchases
of natural gas
|
5.7 | 7.3 | 5.6 | |||||||||
|
Operating
cost reimbursements for shared facilities
|
(3.4 | ) | (2.8 | ) | (1.7 | ) | ||||||
|
Other
expenses with Energy Transfer Equity
|
(0.7 | ) | 3.1 | 1.1 | ||||||||
|
Other
related party expenses, primarily with Evangeline
|
-- | -- | 0.1 | |||||||||
|
Total
related party operating costs and expenses
|
$ | 159.3 | $ | 345.1 | $ | 104.3 | ||||||
|
General
and administrative costs:
|
||||||||||||
|
EPCO
administrative services agreement
|
$ | 10.9 | $ | 15.7 | $ | 11.5 | ||||||
|
Other
related party general and administrative costs
|
-- | (0.8 | ) | (0.1 | ) | |||||||
|
Total
related party general and administrative costs
|
$ | 10.9 | $ | 14.9 | $ | 11.4 | ||||||
The
following table summarizes our related party receivable and payable amounts at
the dates indicated:
|
December
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Accounts
receivable – related parties
|
||||||||
|
EPO
and affiliates (1)
|
$ | 54.3 | $ | 2.3 | ||||
|
Energy
Transfer Equity and affiliates
|
0.2 | 0.9 | ||||||
|
Other
|
-- | 0.1 | ||||||
|
Total
|
$ | 54.5 | $ | 3.3 | ||||
|
Accounts
payable – related parties
|
||||||||
|
EPO
and affiliates
|
$ | 5.5 | $ | 46.1 | ||||
|
EPCO
and affiliates
|
8.1 | 2.4 | ||||||
|
Total
|
$ | 13.6 | $ | 48.5 | ||||
|
(1) EPO
borrowed $45.6 million under a Master Intercompany Loan
Agreement. See “Significant Relationships and Agreements with EPO”
under this Note 15 for more information.
|
||||||||
We
believe that the terms and provisions of our related party agreements are fair
to us; however, such agreements and transactions may not be as favorable to us
as we could have obtained from unaffiliated third parties.
Significant
Relationships and Agreements with EPO
Our assets connect to various midstream
energy assets of EPO and form integral links within EPO’s value
chain. We believe that the operational significance of our assets to
EPO, as well as the alignment of our respective economic interests in these
assets, will result in a collaborative effort to promote their operational
efficiency and maximize value. In addition, we believe our
relationship with EPO and EPCO provides us with a distinct benefit in both the
operation of our assets and in the identification and execution of potential
future acquisitions that are not otherwise taken by Enterprise Products Partners
or Enterprise GP Holdings in accordance with our business opportunity
agreements. One of our primary business purposes is to support the
growth objectives of EPO and other affiliates under common control.
At December 31, 2009, EPO beneficially
owned approximately 58.6% of our limited partner interests and 100% of our
general partner. EPO was sponsor of the DEP I and DEP II drop down
transactions and owns varying interests (as Parent) in the DEP I and DEP II
Midstream Businesses. For a description of the DEP I and DEP II drop
down transactions (including consideration provided to EPO), see Note
1. For a description of EPO’s noncontrolling interest in the income
and net assets of the DEP I and DEP II Midstream Businesses, see Note
13. EPO may contribute or sell other equity interests or assets to
us; however, EPO has no obligations or commitment to make such contributions or
sales to us.
EPO has continued involvement with all
of our subsidiaries, including the following types of transactions: (i) it utilizes our storage
services to support its Mont Belvieu fractionation and other businesses; (ii) it
buys from, and sells to, us natural gas in connection with its normal business
activities; and (iii) it is currently the sole shipper on an NGL pipeline system
located in south Texas that is owned by us.
On December 31, 2009, we and EPO
entered into a master intercompany loan agreement with the DEP I and DEP II
Midstream Businesses. This agreement will be used from time to time
to facilitate cash management efforts in connection with the DEP I and DEP II
Midstream Businesses. On December 31, 2009, we borrowed $1.3 million
and EPO borrowed $45.6 million under the agreement at a market rate of
interest. EPO’s intercompany borrowing is a component of “Accounts
receivable – related parties” on our Consolidated Balance
Sheets. These amounts were subsequently repaid on January 4,
2010. The interest rate applicable to these short-term borrowings was
0.73%. Amounts borrowed by us and the related interest eliminate in
consolidation.
Omnibus
Agreement. On December 8, 2008, we entered into an amended and
restated Omnibus Agreement (the “Omnibus Agreement”) with EPO. The
key provisions of this agreement are summarized as follows:
|
§
|
indemnification
for certain environmental liabilities, tax liabilities and right-of-way
defects with respect to the DEP I and DEP II Midstream Businesses EPO
contributed to us in connection with the respective drop down
transactions;
|
|
§
|
funding
by EPO of 100% of post-February 5, 2007 capital expenditures incurred by
South Texas NGL and Mont Belvieu Caverns with respect to certain expansion
projects under construction at the time of our
IPO;
|
|
§
|
funding
by EPO of 100% of post-December 8, 2008 capital expenditures to complete
the Sherman Extension natural gas
pipeline;
|
|
§
|
a
right of first refusal to EPO in our current and future subsidiaries and a
right of first refusal on the material assets of such subsidiaries, other
than sales of inventory and other assets in the ordinary course of
business; and
|
|
§
|
a
preemptive right with respect to equity securities issued by certain of
our subsidiaries, other than as consideration in an acquisition or in
connection with a loan or debt
financing.
|
We and EPO have also agreed to
negotiate in good faith any necessary amendments to the partnership or company
agreements of the DEP II Midstream Businesses when either party believes that
business circumstances have changed.
Our general partner’s Audit, Conflicts
and Governance (“ACG”) Committee must approve amendments to the Omnibus
Agreement when such amendments would adversely affect our
unitholders.
Neither EPO nor any of its affiliates
are restricted under the Omnibus Agreement from competing against
us. As provided for in the EPCO ASA, EPO and its affiliates may
acquire, construct or dispose of additional midstream energy or other assets in
the future without any obligation to offer us the opportunity to acquire or
construct such assets.
As noted previously, EPO indemnified us
for certain environmental liabilities, tax liabilities and right-of-way defects
associated with the assets it contributed to us in connection with the DEP I and
DEP II drop down transactions. These indemnifications terminated on
February 5, 2010. There is an aggregate cap of $15.0 million on the
amount of indemnity coverage and we are not entitled to indemnification until
the aggregate amount of claims we incur exceeds $250
thousand. Environmental liabilities resulting from a change of law
after February 5, 2007 are excluded from the indemnity. We made no
claims to EPO during the years ended December 31, 2009 and 2008.
For information regarding the funding
by EPO of 100% of certain post-February 5, 2007 capital expenditures of South
Texas NGL and Mont Belvieu Caverns, see “Noncontrolling Interest – DEP I
Midstream Businesses – Parent” under Note 13.
Mont
Belvieu Caverns’ LLC Agreement. The Caverns LLC
Agreement states that if Duncan Energy Partners elects to not participate in
certain projects of Mont Belvieu Caverns, then EPO is responsible for funding
100% of such projects. To the extent such non-participated projects
generate identifiable incremental cash flows for Mont Belvieu Caverns in the
future, the earnings and cash flows of Mont Belvieu Caverns will be adjusted to
allocate such incremental amounts to EPO by special allocation or
otherwise. Under the terms of the Caverns LLC Agreement, Duncan
Energy Partners may elect to acquire a 66% share of these projects from EPO
within 90 days of such projects being placed in service. In November
2008, the Caverns LLC Agreement was amended to provide that EPO would
prospectively receive a special allocation of 100% of the depreciation related
to projects that it has fully funded.
The Caverns LLC Agreement also requires
the allocation to EPO of operational measurement gains and
losses. Operational measurement gains and losses are created when
product is moved between storage wells and are attributable to pipeline and well
connection measurement variances.
For information regarding capital
expenditures funded 100% by EPO under the Caverns LLC Agreement as well as
operational measurement gains and losses allocated to EPO, see “Noncontrolling
Interest – DEP I Midstream Businesses – Parent” under Note 13.
Company
and Limited Partnership Agreements – DEP II Midstream
Businesses. On December 8, 2008, the DEP II Midstream
Businesses amended and restated their governing documents in connection with the
DEP II drop down transaction. Collectively, these amended and
restated agreements provide for the following:
|
§
|
the
acquisition by us from EPO of a 66% general partner interest in Enterprise
GC, a 51% general
|
|
|
partner
interest in Enterprise Intrastate and a 51% member interest in Enterprise
Texas;
|
|
§
|
the
payment of distributions in accordance with an overall “waterfall”
approach that stipulates that to the extent that the DEP II Midstream
Businesses collectively generate cash sufficient to pay distributions to
their partners or members, such cash will be distributed first to us and
then to EPO in amounts sufficient to generate an aggregate annualized
fixed return on their respective investments of
11.85%. Distributions in excess of these amounts will be
distributed 98.0% to EPO and 2.0% to us. The initial annual
fixed return amount of 11.85% will be increased by 2.0% each calendar year
beginning January 1, 2010. For example, the fixed return in
2010, assuming no other adjustments, would be 102% of 11.85%, or
12.087%;
|
|
§
|
the
funding of operating cash flow deficits in accordance with each owner’s
respective partner or member
interest;
|
|
§
|
the
election by either owner to fund cash calls associated with expansion
capital projects. Since December 8, 2008, we have elected to
not participate in such cash calls and, as a result, EPO has funded 100%
of the expansion project costs of the DEP II Midstream
Businesses. If we later elect to participate in any expansion
projects, then we will be required to make a capital contribution for our
share of the project costs.
|
Any capital contributions to fund
expansion projects made by either us or EPO will increase such partner’s
Distribution Base (and hence future priority return amounts) under the company
agreement of Enterprise Texas. As noted, we have declined
participation in expansion project spending since December 8,
2008. As a result, EPO has funded 100% of such growth capital
spending and its Distribution Base has increased from $452.1 million at December
8, 2008 to $817.9 million at December 31, 2009. The DEP Distribution
Base was unchanged at $730.0 million at December 31, 2009.
Common
Unit Purchase Agreement – June 2009 Equity Offering. Pursuant
to a common unit purchase agreement, we repurchased 8,000,000 of our common
units beneficially owned by EPO in June 2009. We repurchased an
additional 943,400 of our common units beneficially owned by EPO in July
2009. The repurchase of common units beneficially owned by EPO was
reviewed and approved by each of the ACG Committees of EPGP and DEP
GP. See Note 12 for additional information regarding our June 2009
equity offering.
Transactions
with TEPPCO. Beginning in 2008, Mont Belvieu Caverns commenced
providing NGL and petrochemical storage services to TEPPCO. For the
period January 2007 through March 2008, we leased from TEPPCO an 11-mile
pipeline that was part of our South Texas NGL System. We discontinued
this lease during the first quarter of 2008 when we completed the construction
of a parallel pipeline. All of our related party activities and
balances with TEPPCO, prior to their merger with EPO, have been aggregated with
related party activities and balances that we present for EPO.
Relationship
with EPCO
We have no employees. All of
our operating functions and general and administrative support services are
provided by employees of EPCO pursuant the ASA. We, Enterprise
Products Partners Enterprise GP Holdings and our respective general partners are
parties to the ASA. The significant terms of the ASA are as
follows:
|
§
|
EPCO
will provide selling, general and administrative services, and management
and operating services, as may be necessary to manage and operate our
businesses, properties and assets (all in accordance with prudent industry
practices). EPCO will employ or otherwise retain the services
of such personnel as may be necessary to provide such
services.
|
|
§
|
We
are required to reimburse EPCO for its services in an amount equal to the
sum of all costs and expenses incurred by EPCO which are directly or
indirectly related to our business or
activities
|
|
|
(including
expenses reasonably allocated to us by EPCO). In addition, we
have agreed to pay all sales, use, excise, value added or similar taxes,
if any, that may be applicable from time to time in respect of the
services provided to us by EPCO.
|
|
§
|
EPCO
will allow us to participate as named insureds in its overall insurance
program, with the associated premiums and other costs being allocated to
us.
|
Our operating costs and expenses
include amounts paid to EPCO for the costs it incurs to operate our facilities,
including compensation of employees. We reimburse EPCO for actual
direct and indirect expenses it incurs related to the operation of our
assets. Likewise, our general and administrative costs include
amounts paid to EPCO for administrative services, including compensation of
employees. In general, our reimbursement to EPCO for administrative
services is either (i) on an actual basis for direct expenses it may incur on
our behalf (e.g., the purchase of office supplies) or (ii) based on an
allocation of such charges between the various parties to the ASA based on the
estimated use of such services by each party (e.g., the allocation of general
legal or accounting salaries based on estimates of time spent on each entity’s
business and affairs). The following table presents a breakout of
costs and expenses related to the ASA and other EPCO transactions for the
periods indicated:
|
For
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Operating
costs and expenses
|
$ | 85.8 | $ | 72.1 | $ | 63.7 | ||||||
|
General
and administrative expenses
|
10.9 | 15.7 | 11.5 | |||||||||
|
Total
costs and expenses
|
$ | 96.7 | $ | 87.8 | $ | 75.2 | ||||||
Since the vast majority of expenses
charged to us under the ASA are on an actual basis (i.e. no mark-up or subsidy
is charged or received by EPCO), we believe that such expenses are
representative of what the amounts would have been on a standalone
basis. With respect to allocated costs, we believe that the
proportional direct allocation method employed by EPCO is reasonable and
reflective of the estimated level of costs we would have incurred on a
standalone basis.
The ASA also addresses potential
conflicts that may arise among Enterprise Products Partners (including EPGP),
Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners
(including DEP GP), and the EPCO Group. The EPCO Group includes EPCO
and its other affiliates, but excludes Enterprise Products Partners, Enterprise
GP Holdings, Duncan Energy Partners and their respective general
partners.
The ASA was amended on January 30,
2009 to provide for the cash reimbursement by us, Enterprise Products Partners
and Enterprise GP Holdings to EPCO of distributions of cash or securities, if
any, made by EPCO Unit to their respective Class B limited partners.
The ASA amendment also extended the term under which EPCO provides services to
the partnership entities from December 2010 to December 2013 and made other
updating and conforming changes.
Relationship
with Evangeline
Acadian Gas sold $155.5 million, $362.9
million and $264.2 million of natural gas to Evangeline, under its natural gas
purchase contract with Evangeline, during the years ended December 31, 2009,
2008 and 2007, respectively. The amount of natural gas purchased by
Evangeline pursuant to this contract averaged approximately 50 BBtus/d during
the twelve months ended December 31, 2009, 2008 and 2007,
respectively. For the years ended December 31, 2008 and 2007,
Evangeline was our largest customer and accounted for 22.7% and 21.7%,
respectively, of our consolidated revenues. For the year ended
December 31, 2009, another related party was our largest customer.
Relationship
with Energy Transfer Equity
Enterprise GP Holdings acquired equity
method investments in Energy Transfer Equity, L.P. (together with its
consolidated subsidiaries, “Energy Transfer Equity”) and its general partner in
May 2007.
As a
result of common control of Enterprise GP Holdings and us, Energy Transfer
Equity became a related party to us. Our revenues from Energy
Transfer Equity are attributable to natural gas transportation
services. Our related party expenses with Energy Transfer Equity
primarily include natural gas purchases for pipeline imbalances, reimbursements
of operating costs for shared facilities and the lease of a pipeline in south
Texas.
Basic earnings per unit is computed by
dividing net income or loss attributable to Duncan Energy Partners allocated to
limited partner interests by the weighted-average number of distribution-bearing
common and Class B units (see Note 12) outstanding during a
period. We have no dilutive securities.
The amount of net income or loss
allocated to limited partner interests is net of our general partner’s share of
such earnings. The following table presents the allocation of net
income to DEP GP for the periods indicated:
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
income attributable to Duncan Energy Partners L.P.
|
$ | 91.1 | $ | 47.9 | $ | 3.6 | ||||||
|
Subtract:
Income allocated to former owners of DEP I Midstream
Businesses
|
-- | -- | (5.0 | ) | ||||||||
|
Add
(subtract): Loss (income) allocated to former owners of
the
DEP II Midstream Businesses
|
-- | (19.6 | ) | 20.6 | ||||||||
|
Net
income allocated to Duncan Energy Partners
|
91.1 | 28.3 | 19.2 | |||||||||
|
Multiplied
by DEP GP ownership interest (weighted-average for period)
|
0.7 | % | 1.7 | % | 2.0 | % | ||||||
|
Net
income allocation to DEP GP
|
$ | 0.6 | $ | 0.5 | $ | 0.4 | ||||||
From the closing of our initial public
offering on February 5, 2007 through December 7, 2008, DEP GP maintained a 2%
general partner interest in us. On December 8, 2008, DEP GP elected
to forego making a cash contribution to us to maintain its 2.0% general partner
interest in connection with the DEP II drop down transaction. As a
result, DEP GP’s general partner interest was reduced to 0.7% beginning December
8, 2008.
The following table presents our
calculation of basic and diluted earnings per unit for the period
indicated:
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
income allocation to Duncan Energy Partners
|
$ | 91.1 | $ | 28.3 | $ | 19.2 | ||||||
|
Less: Income
allocation to DEP GP
|
0.6 | 0.5 | 0.4 | |||||||||
|
Net
income allocation to limited partners
|
$ | 90.5 | $ | 27.8 | $ | 18.8 | ||||||
|
Basic
and diluted earnings per unit:
|
||||||||||||
|
Numerator
(net income allocation to limited partners)
|
$ | 90.5 | $ | 27.8 | 18.8 | |||||||
|
Denominator
(weighted-average units outstanding):
|
||||||||||||
|
Common
units
|
54.5 | 20.3 | 20.3 | |||||||||
|
Class
B units
|
3.2 | 2.5 | -- | |||||||||
|
Total
units
|
57.7 | 22.8 | 20.3 | |||||||||
|
Earnings
per unit
|
$ | 1.57 | $ | 1.22 | $ | 0.93 | ||||||
Litigation
On occasion, we are named as a
defendant in litigation relating to our normal business operations, including
regulatory and environmental matters. Although we insure against
various business risks to the extent we believe it is prudent, there is no
assurance that the nature and amount of such insurance will be adequate, in
every case, to indemnify us against liabilities arising from future legal
proceedings as a result of our ordinary business activity. We are not
aware of any litigation, pending or threatened, that we believe is reasonably
likely to have a significant adverse effect on our financial position, results
of operations or cash flows.
Redelivery
Commitments
We transport and store natural gas and
NGLs and store petrochemical products for third parties under various
contracts. These volumes are: (i) accrued as product payables on our
Consolidated Balance Sheets; (ii) in transit for delivery to our customers; or
(iii) held at our storage facilities for redelivery to our
customers. We are insured against any physical loss of such volumes
due to catastrophic events. Under the terms of our NGL and
petrochemical product storage agreements, we are generally required to redeliver
volumes to the owner on demand. At December 31, 2009, NGL and
petrochemical products aggregating 20.9 million barrels were due to be
redelivered to their owners along with 5,015 BBtus of natural
gas. See Note 2 for more information regarding accrued product
payables.
Regulatory
Matters
Certain recent scientific studies have
suggested that emissions of certain gases, commonly referred to as “greenhouse
gases” and including carbon dioxide and methane, may be contributing to climate
change. 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 intended to reduce the emissions
of greenhouse gases in the United States and would require most sources of
greenhouse gas emissions to obtain greenhouse gas emission “allowances”
corresponding to their annual emissions of greenhouse gases. The U.S.
Senate has also begun work on its own legislation for controlling and reducing
emissions of greenhouse gases in the United States. In addition, on
December 7, 2009, the U.S. Environmental Protection Agency (“EPA”) announced its
finding that emissions of greenhouse gases presented an endangerment to human
health and the environment. These findings by the EPA allow the
agency to proceed with the adoption and implementation of regulations that would
restrict emissions of greenhouse gases under existing provisions of the federal
Clean Air Act. Although it may take the EPA several years to adopt
and impose regulations limiting emissions of greenhouse gases, any such
regulation could require us to incur costs to reduce emissions of greenhouse
gases associated with our operations. Any laws or regulations that
may be adopted to restrict or reduce emissions of greenhouse gases would likely
require us to incur increased operating costs, and may have an adverse effect on
our business, financial position, demand for our operations, results of
operations and cash flows.
Contractual
Obligations
The following table summarizes our
significant contractual obligations at December 31, 2009. A
description of each type of contractual obligation follows (dollars in
millions):
|
Payment
or Settlement due by Period
|
||||||||||||||||||||||||||||
|
Contractual
Obligations (1)
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
|||||||||||||||||||||
|
Scheduled
maturities of long term debt (2)
|
$ | 457.3 | $ | -- | $ | 457.3 | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
Estimated
cash interest payments (3)
|
$ | 14.8 | $ | 11.1 | $ | 3.7 | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
Operating
lease obligations
|
$ | 115.6 | $ | 9.0 | $ | 8.9 | $ | 8.7 | $ | 7.4 | $ | 6.6 | $ | 75.0 | ||||||||||||||
|
Purchase
obligations:
|
||||||||||||||||||||||||||||
|
Product
purchase commitments:
|
||||||||||||||||||||||||||||
|
Estimated
payment obligations:
|
||||||||||||||||||||||||||||
|
Natural
gas
|
$ | 511.7 | $ | 257.3 | $ | 127.0 | $ | 127.4 | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
Other
|
$ | 0.1 | $ | * | $ | * | $ | * | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
Underlying
major volume commitments:
|
||||||||||||||||||||||||||||
|
Natural
gas (in BBtus)
|
77,207 | 40,657 | 18,250 | 18,300 | -- | -- | -- | |||||||||||||||||||||
|
Capital
expenditure commitments (4)
|
$ | 175.3 | $ | 175.3 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
*
Indicates amounts are immaterial and less than $0.1
million.
|
||||||||||||||||||||||||||||
|
(1)
The
contractual obligations presented in this table reflect 100% of our
subsidiaries obligations even though we own less than a 100% equity
interest in our operating subsidiaries.
(2)
See
Note 11 for additional information regarding our credit
facilities.
(3)
Our
estimated cash payments for interest are based on the principle amount of
consolidated debt obligations outstanding at December 31, 2009. With
respect to variable-rate debt, we applied the weighted-average interest
rates paid during 2009. See Note 11 for information regarding
variable interest rates charged in 2009 under our credit
agreements. In addition, our estimate of cash payments for interest
gives effect to interest rate swap agreements in place at December 31,
2009. See Note 6 for information regarding our derivative
instruments.
(4)
Capital
expenditure commitments are reflected on a 100% basis before contributions
from noncontrolling interest in connection with the Omnibus Agreement and
Caverns LLC Agreement (see Note 15).
|
||||||||||||||||||||||||||||
Operating
lease obligations. We lease certain
property, plant and equipment under noncancelable and cancelable operating
leases. Amounts shown in the preceding table represent minimum cash
lease payment obligations under our operating leases with terms in excess of one
year.
Our significant lease agreements
involve (i) the lease of underground caverns for the storage of natural gas and
NGLs, primarily our lease for the Wilson natural gas storage facility and (ii)
land held pursuant to right-of-way agreements.
We lease the Wilson natural gas storage
facility, which is integral to the operations of our Texas Intrastate
System. The current term on the Wilson facility lease expires in
2028. In accordance with this lease, we have the option to purchase
the Wilson facility at either December 31, 2024 for $61.0 million or January 25,
2028 for $55.0 million. In addition, the lessor, at its election, may
cause us to purchase the Wilson facility for $65.0 million at the end of any
calendar quarter extending through December 31, 2023.
In addition, our pipeline operations
have entered into leases for land held pursuant to right-of-way
agreements. Our significant right-of-way agreements have original
terms that range from five to 50 years and include renewal options that
could extend the agreements for up to an additional
25 years. Our rental payments are generally at fixed rates, as
specified in the individual contracts, and may be subject to escalation
provisions for inflation and other market-determined factors.
Lease expense is charged to operating
costs and expenses on a straight line basis over the period of expected economic
benefit. Contingent rental payments are expensed as
incurred. We are generally required to perform routine maintenance on
the underlying leased assets. In addition, certain leases give us the
option to make leasehold improvements. Maintenance and repairs of
leased assets resulting from our operations are charged to expense as
incurred. We did not make any significant leasehold improvements
during the years ended December 31, 2009, 2008 or 2007. Lease expense
included in costs and expenses was $9.8 million, $10.8 million and $9.9 million
for the twelve months ended December 31, 2009, 2008 and 2007,
respectively.
Purchase
Obligations. We define
purchase obligations as agreements to purchase goods or services that are
enforceable and legally binding (unconditional) on us that specify all
significant terms, including: fixed or minimum quantities to be purchased;
fixed, minimum or variable price provisions; and the approximate timing of the
transactions.
We have long and short-term product
purchase obligations for natural gas with third-party suppliers. Our
most significant product purchase obligation is a commitment that Acadian Gas
has for the purchase of natural gas in Louisiana (see Note 9) that expires
in January 2013. The prices that we are obligated to pay under these
contracts approximate market prices at the time we take delivery of the
volumes. The preceding table shows our volume commitments and
estimated payment obligations under these contracts for the periods
indicated. Our estimated future payment obligations are based on the
contractual price at December 31, 2009 applied to all future volume
commitments. Actual future payment obligations may vary depending on
market prices at the time of delivery. At December 31, 2009, we
do not have any other product purchase commitments with fixed or minimum pricing
provisions having remaining terms in excess of one year.
We also have short-term payment
obligations relating to capital projects we have initiated. These
commitments represent unconditional payment obligations that we have agreed to
pay vendors for services to be rendered or products to be delivered in
connection with our capital spending programs. The contractual
obligations table shows these capital project commitments for the periods
indicated.
At December 31, 2009, we had
approximately $175.3 million of consolidated capital expenditure commitments
outstanding. These commitments primarily relate to announced
expansions of the Acadian Gas System (i.e., the Haynesville Extension) and the
Texas Intrastate System (i.e., the Sherman Extension and Trinity River
Lateral). Currently, we have not elected to participate in these
expansion projects; therefore, EPO will fund 100% of such costs. We
may elect to participate in such projects in the future. For
information regarding our relationship with EPO and related project funding
arrangements, see Note 15.
Commitments
under Equity Compensation Plans of EPCO
In accordance with our agreements with
EPCO, we reimburse EPCO for our share of its compensation expense associated
with certain employees who perform management, administrative and operating
functions for us (see Note 15). See Note 5 for additional information
regarding accounting for equity awards.
Nature
of Operations in Midstream Energy Industry
Our operations are within the midstream
energy industry. We are engaged in the business of: (i) NGL
transportation, fractionation and marketing; (ii) storage of NGL and
petrochemical products; (iii) transportation of petrochemical products; and (iv)
the gathering, transportation, marketing and storage of natural
gas. As such, our results of operations, cash flows and financial
position may be affected by changes in the commodity prices of these hydrocarbon
products, including changes in the relative price levels among these
products. In general, energy commodity product prices are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors that are beyond our control.
Our profitability could be impacted by
a decline in the volume of hydrocarbon products transported, gathered, stored or
fractionated at our facilities. A material decrease in natural gas or
crude oil production or crude oil refining, for reasons such as depressed
commodity prices or a decrease in exploration and development activities, could
result in a decline in the volume of natural gas and NGLs handled by our
facilities.
A reduction in demand for NGL products
by the petrochemical, refining or heating industries, whether because of:
(i) general economic conditions; (ii) reduced demand by consumers for
the end products made using NGLs; (iii) increased competition from
petroleum-based products due to pricing differences; (iv) adverse weather
conditions; (v) government regulations affecting energy commodity prices,
production levels of hydrocarbons or the content of motor gasoline; or
(vi) other reasons, could adversely affect our results of operations, cash
flows and financial position.
Credit
Risk Due to Industry Concentrations
A substantial portion of our revenues
are derived from companies in the domestic natural gas, NGL and petrochemical
industries. This concentration could affect our overall exposure to
credit risk since these customers may be affected by similar economic or other
conditions. We generally do not require collateral for our accounts
receivable; however, we do attempt to negotiate offset, prepayment, or automatic
debit agreements with customers that are deemed to be credit risks in order to
minimize our potential exposure to any defaults.
Counterparty
Risk with Respect to Derivative Instruments
In those situations where we are
exposed to credit risk in our derivative instrument transactions, we analyze the
counterparty’s financial condition prior to entering into an agreement,
establish credit and/or margin limits and monitor the appropriateness of these
limits on an ongoing basis. Generally, we do not require collateral
nor do we anticipate nonperformance by our counterparties.
Insurance-Related
Risks
We
participate as a named insured in EPCO’s insurance program, which provides us
with property damage, business interruption and other coverages, the scope and
amounts of which are customary and sufficient for the nature and extent of our
operations. While we believe EPCO maintains adequate insurance
coverage on our behalf, insurance will not cover every type of damage or
interruption that might occur. If we were to incur a significant
liability for which we were not fully insured, it could have a material impact
on our consolidated financial position, results of operations and cash
flows. In addition, the proceeds of any such insurance may not be
paid in a timely manner and may be insufficient to reimburse us for our repair
costs or lost income. Any event that interrupts the revenues
generated by our consolidated operations, or which causes us to make significant
expenditures not covered by insurance, could reduce our ability to pay
distributions to our partners and, accordingly, adversely affect the market
price of our common units.
EPCO’s deductible for onshore physical
damage from windstorms is currently $25.0 million per storm. EPCO’s
onshore program currently provides $150.0 million per occurrence for named
windstorm events. For non-windstorm events, EPCO’s deductible for
onshore physical damage is $5.0 million per occurrence. With respect to
business interruption insurance, onshore assets must be out-of-service in excess
of 60 days before any losses from business interruptions will be
covered. Furthermore, pursuant to the current policy, we will now
absorb 50% of the first $50.0 million of any loss in excess of deductible
amounts for our onshore assets. Any amounts expensed by the DEP I and
DEP II Midstream Businesses will be included in net income and EPO’s share of
these losses will be attributed to noncontrolling interest.
In the third quarter of 2008, certain
of our facilities located along the Gulf Coast of Texas and Louisiana were
damaged by Hurricanes Gustav and Ike. As a result of our allocated
share of EPCO’s insurance deductibles for windstorm coverage, we expensed a
combined cumulative total of $2.0 million of repair costs for property damage in
connection with these two storms through December 31, 2009.
Interest
Rate Risk
Our Revolving Credit Facility and Term
Loan Agreement are variable rate debt obligations, which both expire in
2011. We have outstanding $175 million of variable-to-fixed interest rate
swaps, all of which expire in September 2010, that partially hedge our exposure
to changes in variable interest rates.
We cannot predict the costs of
refinancing, at maturity, our existing credit facilities or the costs of new
credit arrangements. A tight credit market, similar to the markets in late
2008 and early 2009, may have an adverse affect on our future ability to
refinance our credit facilities at favorable rates or to enter into additional
new credit arrangements. In addition, tight credit market conditions
may translate into our having to agree to increasingly restrictive lender
covenants. The inability to refinance or enter into new credit
arrangements with favorable terms could impede our ability to fund capital
requirements or to make distributions on our common units.
The following table provides
information regarding: (i) the net effect of changes in our operating assets and
liabilities; (ii) cash payments for interest and (iii) cash payments for income
taxes for the periods indicated.
|
For
the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Decrease
(increase) in:
|
||||||||||||
|
Accounts
receivable - trade
|
$ | 39.6 | $ | 5.0 | $ | 9.7 | ||||||
|
Accounts
receivable - related party
|
(55.5 | ) | 1.2 | (4.2 | ) | |||||||
|
Gas
imbalance receivables
|
25.9 | (1.4 | ) | 28.7 | ||||||||
|
Inventories
|
17.5 | (6.0 | ) | (6.8 | ) | |||||||
|
Prepaid
and other current assets
|
(5.3 | ) | 1.6 | (1.5 | ) | |||||||
|
Increase
(decrease) in:
|
||||||||||||
|
Accounts
payable - trade
|
(1.7 | ) | (5.9 | ) | 15.8 | |||||||
|
Accounts
payable - related party
|
(39.9 | ) | 13.5 | 31.0 | ||||||||
|
Accrued
costs and expenses
|
(42.7 | ) | (10.1 | ) | (47.7 | ) | ||||||
|
Accrued
property taxes
|
0.8 | 1.6 | 1.7 | |||||||||
|
Accrued
taxes - other
|
0.1 | 4.8 | 2.7 | |||||||||
|
Other
current liabilities
|
(19.1 | ) | 6.5 | (16.0 | ) | |||||||
|
Other
long-term liabilities
|
(0.2 | ) | (12.6 | ) | 0.8 | |||||||
|
Net
effect of changes in operating accounts
|
$ | (80.5 | ) | $ | (1.8 | ) | $ | 14.2 | ||||
|
Cash
payments for interest, net of $0.3, $0.3 and
|
||||||||||||
|
$2.6
capitalized in 2009, 2008 and 2007, respectively
|
$ | 13.8 | $ | 11.5 | $ | 11.5 | ||||||
|
Cash
payments for income taxes
|
$ | 1.0 | $ | 0.2 | $ | -- | ||||||
We incurred liabilities for
construction in progress that had not been paid at December 31, 2009, 2008 and
2007 of $41.8 million, $30.5 million and $24.8 million,
respectively. Such amounts are not included under the caption
“Capital expenditures” on the Statements of Consolidated Cash
Flows.
The following table presents the
components of depreciation, amortization and accretion for the periods
indicated:
|
For
the Year Ended December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Depreciation,
amortization and accretion expense:
|
||||||||||||
|
DEP
I Midstream Businesses
|
$ | 38.7 | $ | 34.3 | $ | 28.9 | ||||||
|
DEP
II Midstream Businesses
|
147.4 | 133.1 | 146.6 | |||||||||
|
Duncan
Energy Partners L.P. standalone
|
2.2 | 0.4 | 0.1 | |||||||||
|
Total
|
$ | 188.3 | $ | 167.8 | $ | 175.6 | ||||||
Cash payments for significant business
combinations were $35.0 million for the year ended December 31,
2007. In December 2007, we acquired the South Monco natural gas
pipeline business (“South Monco”) from a third party for $35.0 million in
cash. South Monco primarily consists of 128 miles of pipelines
located in southeast Texas that gather natural gas at the wellhead for regional
producers for redelivery to various points, including our Texas Intrastate
System. The South Monco system includes an amine treating unit and
related dehydration facilities. The South Monco transaction was
accounted for using the purchase method of accounting and, accordingly, such
cost has been allocated to assets acquired and liabilities assumed based on
estimated fair values.
The following table presents selected
quarterly financial data for the years ended December 31, 2009 and
2008:
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||||||
|
For
the Year Ended December 31, 2009:
|
||||||||||||||||
|
Revenues
|
$ | 256.8 | $ | 226.7 | $ | 244.6 | $ | 251.2 | ||||||||
|
Operating
income
|
14.8 | 8.7 | 21.1 | 16.3 | ||||||||||||
|
Net
loss attributable to noncontrolling interest
|
8.9 | 18.7 | 7.0 | 10.7 | ||||||||||||
|
Net
income attributable to Duncan Energy Partners L.P.
|
19.9 | 23.2 | 24.8 | 23.2 | ||||||||||||
|
Allocation
of net income attributable to Duncan Energy Partners L.P.:
|
||||||||||||||||
|
Duncan Energy Partners L.P.
|
||||||||||||||||
|
Limited partners
|
19.8 | 23.0 | 24.6 | 23.1 | ||||||||||||
|
General partner
|
0.1 | 0.2 | 0.2 | 0.1 | ||||||||||||
|
Earnings
per unit (basic and diluted)
|
0.34 | 0.40 | 0.43 | 0.40 | ||||||||||||
|
For
the Year Ended December 31, 2008:
|
||||||||||||||||
|
Revenues
|
363.6 | 478.8 | 432.2 | 323.5 | ||||||||||||
|
Operating
income
|
21.1 | 15.8 | 18.7 | 12.3 | ||||||||||||
|
Net
loss (income) attributable to noncontrolling interest
|
(5.6 | ) | 0.6 | (4.4 | ) | 2.0 | ||||||||||
|
Net
income attributable to Duncan Energy Partners L.P.
|
13.3 | 13.3 | 10.6 | 10.7 | ||||||||||||
|
Allocation
of net income attributable to Duncan Energy Partners L.P.:
|
||||||||||||||||
|
Duncan Energy Partners L.P.
|
||||||||||||||||
|
Limited partners
|
5.9 | 6.5 | 3.7 | 11.7 | ||||||||||||
|
General partner
|
0.1 | 0.1 | 0.1 | 0.2 | ||||||||||||
|
Former owner of DEP II Midstream Businesses
|
7.3 | 6.7 | 6.8 | (1.2 | ) | |||||||||||
|
Earnings
per unit (basic and diluted)
|
0.29 | 0.32 | 0.18 | 0.39 | ||||||||||||
F -
59
Exhibit
12.1
DUNCAN
ENERGY PARTNERS L.P.
COMPUTATION
OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars
in millions)
|
|
For
the Years Ended December 31,
|
|||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Consolidated
net income
|
$ | 45.8 | $ | 55.3 | $ | 23.6 | $ | 51.7 | $ | 30.1 | ||||||||||
|
Add:
Provision for income taxes
|
1.3 | 1.1 | 4.2 | 1.7 | -- | |||||||||||||||
|
Less: Equity
in income of Evangeline
|
(1.1 | ) | (0.9 | ) | (0.2 | ) | (1.0 | ) | (0.3 | ) | ||||||||||
|
Consolidated
pre-tax income before equity earnings from Evangeline
|
46.0 | 55.5 | 27.6 | 52.4 | 29.8 | |||||||||||||||
|
Add: Fixed
charges
|
17.6 | 15.3 | 14.5 | 3.2 | 3.1 | |||||||||||||||
|
Amortization
of capitalized interest
|
4.0 | 1.0 | 0.6 | -- | -- | |||||||||||||||
|
Subtotal
|
67.6 | 71.8 | 42.7 | 55.6 | 32.9 | |||||||||||||||
|
Less: Interest
capitalized
|
(0.3 | ) | (0.3 | ) | (2.6 | ) | -- | -- | ||||||||||||
|
Net
loss (income) attributable to noncontrolling interest:
|
||||||||||||||||||||
|
DEP
I Midstream Businesses - Parent
|
(15.3 | ) | (11.4 | ) | (20.0 | ) | -- | -- | ||||||||||||
|
DEP
II Midstream Businesses - Parent
|
60.6 | 4.0 | -- | -- | -- | |||||||||||||||
|
Total
earnings
|
$ | 112.6 | $ | 64.1 | $ | 20.1 | $ | 55.6 | $ | 32.9 | ||||||||||
|
Fixed
charges:
|
||||||||||||||||||||
|
Interest
expense
|
$ | 14.0 | $ | 11.4 | $ | 8.6 | $ | -- | $ | -- | ||||||||||
|
Capitalized
interest
|
0.3 | 0.3 | 2.6 | -- | -- | |||||||||||||||
|
Interest
portion of rental expense
|
3.3 | 3.6 | 3.3 | 3.2 | 3.1 | |||||||||||||||
|
Total
|
$ | 17.6 | $ | 15.3 | $ | 14.5 | $ | 3.2 | $ | 3.1 | ||||||||||
|
Ratio
of earnings to fixed assets
|
6.4x | 4.2x | 1.4x | 17.4x | 10.6x | |||||||||||||||
These
computations take into account our consolidated operations and the distributed
income from our equity method investee. For purposes of these
calculations, “earnings” is the amount resulting from adding and subtracting the
following items:
Add the following, as
applicable:
|
§
|
consolidated
pre-tax income before income or loss from our equity
investee;
|
|
§
|
fixed
charges;
|
|
§
|
amortization
of capitalized interest;
|
|
§
|
distributed
income of our equity investee; and
|
|
§
|
our
share of pre-tax losses of our equity investee for which charges arising
from guarantees are included in fixed
charges.
|
From the
subtotal of the added items, subtract the following, as applicable:
|
§
|
interest
capitalized;
|
|
§
|
preference
security dividend requirements of consolidated subsidiaries;
and
|
|
§
|
noncontrolling
interest in pre-tax income of subsidiaries that have not incurred fixed
charges.
|
The term
“fixed charges” means the sum of the following: interest expensed and
capitalized; amortized premiums, discounts and capitalized expenses related to
indebtedness; an estimate of interest within rental expenses; and preference
dividend requirements of consolidated subsidiaries.
Our ratio
is significantly higher for the years ended December 31, 2006 and 2005 because
we did not have any interest expense, capitalized interest expense or
noncontrolling interest in income of subsidiaries.
Exhibit
21.1
LIST
OF SUBSIDIARIES
DUNCAN
ENERGY PARTNERS L.P.
as
of February 1, 2010
|
Jurisdiction
|
Direct
and Indirect
|
|
|
Name
of Subsidiary
|
of
Formation
|
Effective
Ownership
|
|
Acadian
Gas, LLC
|
Delaware
|
66%
|
|
Acadian
Gas Pipeline System
|
Texas
|
100%
|
|
Calcasieu
Gas Gathering System
|
Texas
|
100%
|
|
Cypress
Gas Marketing, LLC
|
Delaware
|
100%
|
|
Cypress
Gas Pipeline, LLC
|
Delaware
|
100%
|
|
DEP
Offshore Port System, LLC
|
Texas
|
100%
|
|
DEP
OLPGP, LLC
|
Delaware
|
100%
|
|
DEP
Operating Partnership, L.P.
|
Delaware
|
100%
|
|
Enterprise
Big Thicket Pipeline System LLC
|
Texas
|
66%
|
|
Enterprise
GC, L.P.
|
Delaware
|
66%
|
|
Enterprise
Holding III, LLC
|
Delaware
|
100%
|
|
Enterprise
Intrastate L.P.
|
Delaware
|
51%
|
|
Enterprise
Lou-Tex Propylene Pipeline L.P.
|
Delaware
|
66%
|
|
Enterprise
Texas Pipeline LLC
|
Texas
|
51%
(1)
|
|
Evangeline
Gulf Coast Gas, LLC
|
Delaware
|
100%
|
|
MCN
Acadian Gas Pipeline, LLC
|
Delaware
|
100%
|
|
MCN
Pelican Interstate Gas, LLC
|
Delaware
|
100%
|
|
Mont
Belvieu Caverns, LLC
|
Delaware
|
66%
|
|
Neches
Pipeline System
|
Texas
|
100%
|
|
Pontchartrain
Natural Gas System
|
Texas
|
100%
|
|
Sabine
Propylene Pipeline L.P.
|
Texas
|
66%
|
|
South
Texas NGL Pipelines, LLC
|
Delaware
|
66%
|
|
Tejas-Magnolia
Energy, LLC
|
Delaware
|
100%
|
|
TXO-Acadian
Gas Pipeline, LLC
|
Delaware
|
100%
|
(1)
Reflects a 51% voting membership interest. The economic interest of
this membership interest includes tiered preference distributions and priority
returns.
Exhibit
23.1
CONSENT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We
consent to the incorporation by reference in (i) Registration Statement
Nos. 333-149583 and 333-163842 of Duncan Energy Partners L.P. on Form S-3;
and (ii) Registration Statement No. 333-164852 of Duncan Energy Partners L.P. on
Form S-8 of our reports dated March 1, 2010, relating to the consolidated
financial statements of Duncan Energy Partners L.P. and subsidiaries (which
report expresses an unqualified opinion and includes an explanatory
paragraph indicating the financial statements of the Company were prepared
from the separate records maintained by Enterprise Products Partners L.P. or
affiliates and may not necessarily be indicative of the conditions that would
have existed or the results of operations if the Company had been operated as an
unaffiliated entity), and the effectiveness of Duncan Energy Partners L.P. and
subsidiaries’ internal control over financial reporting, appearing in this
Annual Report on Form 10-K of Duncan Energy Partners L.P. for the year ended
December 31, 2009.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
March 1,
2010
EXHIBIT
31.1
CERTIFICATIONS
I,
Richard H. Bachmann, certify that:
|
1.
|
I
have reviewed this annual report on Form 10–K of Duncan Energy Partners
L.P.;
|
|
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 financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-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 the 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 the 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: March 1, 2010 | /s/ Richard H. Bachmann | |
| Name: Richard H. Bachmann | ||
| Title: Chief Executive Officer of DEP Holdings, LLC, | ||
| the General Partner of Duncan Energy Partners L.P. |
EXHIBIT
31.2
|
|
CERTIFICATIONS
|
I, W.
Randall Fowler, certify that:
|
1.
|
I
have reviewed this annual report on Form 10–K of Duncan Energy Partners
L.P.;
|
|
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 financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-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 the 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 the 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: March 1, 2010 |
/s/ W. Randall
Fowler
|
|
| Name: W. Randall Fowler | ||
| Title: Chief Financial Officer of DEP Holdings, LLC, | ||
| the General Partner of Duncan Energy Partners L.P. |
EXHIBIT
32.1
SARBANES-OXLEY
SECTION 906 CERTIFICATION
CERTIFICATION OF RICHARD H. BACHMANN, CHIEF EXECUTIVE
OFFICER
OF
DEP HOLDINGS, LLC, THE GENERAL PARTNER OF
DUNCAN
ENERGY PARTNERS L.P.
In
connection with this annual report of Duncan Energy Partners L.P. (the
“Registrant”) on Form 10-K for the year ended December 31, 2009 as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I,
Richard H. Bachmann, Chief Executive Officer of DEP Holdings, LLC, the General
Partner of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted
pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
|
(1)
|
The
Report fully complies with the requirements of Section 13(a) 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
Registrant.
|
| /s/ Richard H. Bachmann | |
| Name: Richard H. Bachmann | |
| Title: Chief Executive Officer of DEP Holdings, LLC, | |
| the General Partner of Duncan Energy Partners L.P. | |
| Date: March 1, 2010 |
EXHIBIT
32.2
SARBANES-OXLEY
SECTION 906 CERTIFICATION
CERTIFICATION
OF W. RANDALL FOWLER, CHIEF FINANCIAL OFFICER
OF
DEP HOLDINGS, LLC, THE GENERAL PARTNER OF
DUNCAN
ENERGY PARTNERS L.P.
In
connection with this annual report of Duncan Energy Partners L.P. (the
“Registrant”) on Form 10-K for the year ended December 31, 2009 as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I, W.
Randall Fowler, Chief Financial Officer of DEP Holdings, LLC, the General
Partner of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted
pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
|
(1)
|
The
Report fully complies with the requirements of Section 13(a) 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
Registrant.
|
| /s/ W. Randall Fowler | |
| Name: W. Randall Fowler | |
| Title: Chief Financial Officer of DEP Holdings, LLC, | |
| the General Partner of Duncan Energy Partners L.P. | |
| Date: March 1, 2010 |