Attached files
| file | filename |
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| 8-K - CURRENT REPORT - ENTERPRISE PRODUCTS PARTNERS L.P. | epdform8k_030810.htm |
| EX-23.1 - EXHIBIT 23.1 - ENTERPRISE PRODUCTS PARTNERS L.P. | exhibit23_1.htm |
EXHIBIT
99.1
Enterprise
Products GP, LLC
Consolidated
Balance Sheet at December 31, 2009
and
Report of Independent Registered Public Accounting Firm
TABLE
OF CONTENTS
|
Page
No.
|
||
To the
Board of Directors of Enterprise Products GP, LLC
Houston,
Texas
We have
audited the accompanying consolidated balance sheet of Enterprise Products GP,
LLC and subsidiaries (the "Company") as of December 31, 2009. This
consolidated balance sheet is the responsibility of the Company's
management. Our responsibility is to express an opinion on this
consolidated balance sheet 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 the balance
sheet is free of material misstatement. The Company is not required to have, nor
were we engaged to perform, an audit of its internal control over financial
reporting. Our audit included consideration of internal control over financial
reporting as a basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a
test basis, evidence supporting the amounts and disclosures in the balance
sheet, assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall consolidated balance sheet
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our
opinion, such consolidated balance sheet presents fairly, in all material
respects, the financial position of Enterprise Products GP, LLC and subsidiaries
at December 31, 2009, in conformity with accounting principles generally
accepted in the United States of America.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
March 1,
2010
CONSOLIDATED
BALANCE SHEET
AT
DECEMBER 31, 2009
(Dollars
in millions)
|
ASSETS
|
||||
|
Current
assets:
|
||||
|
Cash
and cash equivalents
|
$ | 54.7 | ||
|
Restricted
cash
|
63.6 | |||
|
Accounts
and notes receivable – trade, net of allowance for doubtful accounts of
$16.8
|
3,099.0 | |||
|
Accounts
receivable – related parties
|
38.4 | |||
|
Inventories
(see Note 6)
|
711.9 | |||
|
Derivative
assets (see Note 5)
|
113.8 | |||
|
Prepaid
and other current assets
|
165.5 | |||
|
Total
current assets
|
4,246.9 | |||
|
Property,
plant and equipment, net
|
17,689.2 | |||
|
Investments
in unconsolidated affiliates
|
890.6 | |||
|
Intangible
assets, net of accumulated amortization of $795.0
|
1,064.8 | |||
|
Goodwill
|
2,018.3 | |||
|
Other
assets
|
241.8 | |||
|
Total
assets
|
$ | 26,151.6 | ||
|
LIABILITIES
AND EQUITY
|
||||
|
Current
liabilities:
|
||||
|
Accounts
payable – trade
|
$ | 410.6 | ||
|
Accounts
payable – related parties
|
69.8 | |||
|
Accrued
product payables
|
3,393.0 | |||
|
Accrued
interest
|
228.0 | |||
|
Other
accrued expenses
|
108.5 | |||
|
Derivative
liabilities (see Note 5)
|
93.0 | |||
|
Other
current liabilities
|
233.1 | |||
|
Total
current liabilities
|
4,536.0 | |||
|
Long-term debt: (see
Note 11)
|
||||
|
Senior
debt obligations – principal
|
9,764.3 | |||
|
Junior
subordinated notes – principal
|
1,532.7 | |||
|
Other
|
49.4 | |||
|
Total
long-term debt
|
11,346.4 | |||
|
Deferred
tax liabilities
|
71.7 | |||
|
Other
long-term liabilities
|
155.2 | |||
|
Commitments and contingencies
(see Note 16)
|
||||
|
Equity: (see Note
12)
|
||||
|
Member’s
interest
|
593.9 | |||
|
Accumulated
other comprehensive loss
|
(0.2 | ) | ||
|
Total
member’s equity
|
593.7 | |||
|
Noncontrolling
interest
|
9,448.6 | |||
|
Total
equity
|
10,042.3 | |||
|
Total
liabilities and equity
|
$ | 26,151.6 | ||
See Notes
to Consolidated Balance Sheet.
Except
as noted within the context of each footnote disclosure, the dollar amounts
presented in the tabular data within these footnote disclosures are stated in
millions of dollars.
Company
Organization
Enterprise
Products GP, LLC is a Delaware limited liability company that was formed in
April 1998 to become the general partner of Enterprise Products Partners
L.P. The business purpose of Enterprise Products GP, LLC is to manage
the affairs and operations of Enterprise Products Partners L.P. At
December 31, 2009, Enterprise GP Holdings L.P. owned 100% of the membership
interests of Enterprise Products GP, LLC.
Unless
the context requires otherwise, references to “we,” “us,” “our” or “Enterprise
Products GP, LLC” are intended to mean and include the business and operations
of Enterprise Products GP, LLC, as well as its consolidated subsidiaries, which
include Enterprise Products Partners L.P. and its consolidated
subsidiaries. References to “EPGP” mean Enterprise Products GP, LLC,
individually as the general partner of Enterprise Products Partners, and not on
a consolidated basis.
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
registered common units of which are listed on the New York Stock Exchange
(“NYSE”) under the ticker symbol “EPD.” Enterprise Products Partners
has no business activities outside those conducted by its operating subsidiary,
Enterprise Products Operating LLC (“EPO”). Enterprise Products
Partners and EPO were formed to acquire, own and operate certain natural gas
liquids (“NGLs”) related businesses of Enterprise Products Company.
References
to “Enterprise GP Holdings” mean the business and operations of Enterprise GP
Holdings L.P. and its consolidated subsidiaries. Enterprise GP
Holdings is a publicly traded Delaware limited partnership, the registered units
of which are listed on the NYSE under the ticker symbol
“EPE.” References to “EPE Holdings” mean EPE Holdings, LLC, which is
the general partner of Enterprise GP Holdings.
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 our subsidiaries. On
October 26, 2009, Enterprise Products Partners completed the mergers with TEPPCO
and TEPPCO GP (such related mergers referred to herein individually and together
as the “TEPPCO Merger”).
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.
References
to “EPCO” mean Enterprise Products Company (formerly EPCO, Inc.) and its
privately held affiliates. We, EPO, Duncan Energy Partners, 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.
For
financial reporting purposes, Enterprise Products Partners consolidates the
balance sheet of Duncan Energy Partners L.P. (“Duncan Energy Partners”) with
that of its own. Enterprise Products Partners controls Duncan Energy
Partners through the ownership of its general partner, DEP Holdings, LLC (“DEP
GP”). Public ownership of Duncan Energy Partners’ net assets is
presented as a component of noncontrolling interest in our Consolidated Balance
Sheet. The borrowings of Duncan Energy Partners are presented as part
of our consolidated debt; however, neither Enterprise Products Partners nor EPGP
have any obligation for the payment of interest or repayment of borrowings
incurred by Duncan Energy Partners.
Basis
of Presentation
EPGP owns
a 2% general partner interest in Enterprise Products Partners, which conducts
substantially all of its business. EPGP has no independent operations
and no material assets outside those of Enterprise Products
Partners. The number of reconciling items between our consolidated
balance sheet and that of Enterprise Products Partners are few. The
most significant difference is that relating to noncontrolling interest
ownership in our net assets by the limited partners of Enterprise Products
Partners, and the elimination of our investment in Enterprise Products Partners
with our underlying capital account in Enterprise Products
Partners.
On
October 26, 2009, the related mergers of our wholly owned subsidiaries with
TEPPCO and TEPPCO GP were completed. Under terms of the merger
agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of ours, and
each of TEPPCO’s unitholders, except for a privately held affiliate of EPCO,
were entitled to receive 1.24 of Enterprise Products Partners’ common units for
each TEPPCO unit. In total, we issued an aggregate of 126,932,318
common units and 4,520,431 Class B units (described below) as consideration in
the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership
interests. TEPPCO’s units, which had been trading on the NYSE under
the ticker symbol “TPP,” have been delisted and are no longer publicly
traded. On October 27, 2009, our TEPPCO and TEPPCO GP equity
interests were contributed to EPO, and TEPPCO and TEPPCO GP became wholly owned
subsidiaries of EPO.
A
privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based
on the 1.24 exchange rate, for 4,520,431 of Enterprise Products Partners’ Class
B units in lieu of common units. The Class B units are not entitled
to regular quarterly cash distributions for the first sixteen quarters following
the closing date of the merger. The Class B units automatically
convert into the same number of common units on the date immediately following
the payment date for the sixteenth quarterly distribution following the closing
date of the merger. The Class B units are entitled to vote together
with the common units as a single class on partnership matters and, except for
the payment of distributions, have the same rights and privileges as Enterprise
Products Partners’ common units.
Since
Enterprise Products Partners, TEPPCO and TEPPCO GP are under common control of
EPCO and its affiliates, the TEPPCO Merger was accounted for at historical costs
as a reorganization of entities under common control in a manner similar to a
pooling of interests.
We
revised our business segments and related disclosures to reflect the TEPPCO
Merger. Our reorganized business segments reflect the manner in which
these businesses are managed and reviewed by the chief executive officer of
EPGP. Under our new business segment structure, we have five
reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore
Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines &
Services; (iv) Offshore Pipelines & Services and (v) Petrochemical &
Refined Products Services.
Our
balance sheet has been prepared in accordance with U.S. generally accepted
accounting principles (“GAAP”).
Allowance
for Doubtful Accounts
Our
allowance for doubtful accounts is determined based on specific identification
and estimates of future uncollectible accounts. Our procedure for
determining the allowance for doubtful accounts is based on: (i) historical
experience with customers, (ii) the perceived financial stability of customers
based on our research and (iii) the levels of credit we grant to
customers. In addition, we may increase the allowance account in
response to the specific identification of customers involved in bankruptcy
proceedings and similar financial difficulties. On a routine basis,
we review estimates associated with the allowance for doubtful accounts to
ensure that we have recorded sufficient reserves to cover potential
losses. Our allowance also includes estimates for uncollectible
natural gas imbalances based on specific identification of
accounts.
The
following table presents the activity of our allowance for doubtful accounts for
the year ended December 31, 2009:
|
Balance
at beginning of period
|
$ | 17.7 | ||
|
Charges
to expense
|
0.1 | |||
|
Payments
|
(1.0 | ) | ||
|
Balance
at end of period
|
$ | 16.8 |
See “Credit Risk Due to Industry
Concentrations” in Note 17 for additional information.
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.
Consolidation
Policy
Our
consolidated balance sheet includes 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 also consolidate other
entities and ventures in which we possess a controlling financial interest as
well as partnership interests where we are the sole general partner of the
partnership. 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 balance sheets of such businesses with those of our
own. Third-party or affiliate ownership interests in our controlled
subsidiaries are presented as noncontrolling interests. See Note 12
for information regarding noncontrolling interest.
If the
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 entity’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 entity’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 Sheet
(or those of our equity method investments) in inventory or similar
accounts.
If our
ownership interest in an entity does not provide us with either control or
significant influence we account for the investment using the cost
method.
Contingencies
Certain
conditions may exist as of the date our balance sheet is 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 its legal counsel
assess such contingent liabilities, and such assessment inherently involves 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 on our balance sheet. If the
assessment indicates that a potentially 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 and material), 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 Sheet, all
components of current assets and current liabilities that exceed 5% of total
current assets and liabilities, respectively.
Deferred
Revenues
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,
deferred revenues totaled $106.8 million and were recorded as a component of
other current and long-term liabilities, as appropriate, on our Consolidated
Balance Sheet.
Derivative
Instruments
We use
derivative instruments such as swaps, forwards and other contracts to manage
price risks associated with inventories, firm commitments, interest rates,
foreign currency 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. See Note 5 for additional information
regarding our derivative instruments and related hedging
activities.
Environmental
Costs
Environmental
costs for remediation are accrued based on estimates of known remediation
requirements. Such accruals are based on management’s best 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 year
ended December 31, 2009:
|
Balance
at beginning of period
|
$ | 22.3 | ||
|
Charges
to expense
|
1.9 | |||
|
Acquisition-related
additions and other
|
-- | |||
|
Payments
|
(5.1 | ) | ||
|
Adjustments
|
(2.4 | ) | ||
|
Balance
at end of period
|
$ | 16.7 |
At
December 31, 2009, $6.4 million of our environmental reserves were classified as
current liabilities.
Equity
Awards
See Note
4 for information regarding our accounting for equity awards.
Estimates
Preparing
our Consolidated Balance Sheet in conformity with GAAP requires management to
make estimates and assumptions that affect amounts presented on the balance
sheet (i.e. assets and liabilities) and disclosures about contingent assets and
liabilities. 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.
Exchange
Contracts
Exchanges
are contractual agreements for the movements of NGLs and certain petrochemical
products between parties to satisfy timing and logistical needs of the
parties. Net exchange volumes borrowed from us under such agreements
are valued at market-based prices and included in accounts
receivable. Net exchange volumes loaned to us under such agreements
are valued at market-based prices and accrued as a liability in accrued product
payables.
Receivables
and payables arising from exchange transactions are settled with movements of
products rather than with cash. When payment or receipt of monetary
consideration is required for product differentials and service costs, such
items are recognized in our Consolidated Balance Sheet on a net basis. Exchanges
are contractual agreements for the movements of NGLs and certain petrochemical
products between parties to satisfy timing and logistical needs of the
parties. Net exchange volumes borrowed from us under such agreements
are valued at market-based prices and included in accounts
receivable. Net exchange volumes loaned to us under such agreements
are valued at market-based prices and accrued as a liability in accrued product
payables.
Receivables and payables arising from
exchange transactions are settled with movements of products rather than with
cash. When payment or receipt of monetary consideration is required
for product differentials and service costs, such items are recognized in our
Consolidated Balance Sheet on a net basis.
Fair
Value Information
Cash and
cash equivalents and restricted cash, accounts receivable, accounts payable and
accrued expenses, and other current liabilities are carried at amounts which
reasonably approximate their fair values due to their short-term
nature. The estimated fair values of our fixed-rate debt are based on
quoted market prices for such debt or debt of similar terms and
maturities. The carrying amounts of our variable-rate debt
obligations reasonably approximate their fair values due to their variable
interest rates. See Note 5 for fair value information associated with
our derivative instruments.
The
following table presents the estimated fair values of our financial instruments
at December 31, 2009:
|
Carrying
|
Fair
|
|||||||
|
Financial
Instruments
|
Value
|
Value
|
||||||
|
Financial
assets:
|
||||||||
|
Cash
and cash equivalents and restricted cash
|
$ | 118.3 | $ | 118.3 | ||||
|
Accounts
receivable
|
3,137.4 | 3,137.4 | ||||||
|
Financial
liabilities:
|
||||||||
|
Accounts
payable and accrued expenses
|
4,209.9 | 4,209.9 | ||||||
|
Other
current liabilities
|
233.1 | 233.1 | ||||||
|
Fixed-rate
debt (principal amount)
|
10,586.7 | 11,056.2 | ||||||
|
Variable-rate
debt
|
710.3 | 710.3 | ||||||
Foreign
Currency Translation
We own an
NGL marketing business located in Canada. The balance sheet of this
foreign subsidiary is translated into U.S. dollars from the Canadian dollar,
which is the subsidiary’s functional currency, using the current rate
method. Its assets and liabilities are translated at the rate of
exchange in effect at the balance sheet date. Exchange gains and
losses arising from foreign currency translation adjustments are reflected as
separate components of accumulated other comprehensive loss (“AOCI”) in the
accompanying Consolidated Balance Sheet. Our net cash flows from this
Canadian subsidiary may be adversely affected by changes in foreign currency
exchange rates. See Note 5 for information regarding our foreign
currency derivative instruments.
Impairment
Testing for Goodwill
Our
goodwill amounts are assessed for impairment (i) on a routine annual basis 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. See Note 5 for information regarding impairment charges
related to goodwill during 2009.
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 when 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 5 for information regarding impairment charges related to long-lived assets
during 2009.
Income
Taxes
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.
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. Since we do not have access to information regarding each
partner’s tax basis, we cannot readily determine the total difference in the
basis of our net assets for financial and tax reporting purposes.
We must
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. See Note 15 for additional information regarding our
income taxes.
Impairment
Testing for Unconsolidated Affiliates
We
evaluate our equity method investments for impairment when events or changes in
circumstances indicate that there is a loss in value of the investment
attributable to an other than 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.
Inventories
Inventories
primarily consist of natural gas, NGLs, crude oil, refined products, lubrication
oils and certain petrochemical products that are valued at the lower of average
cost or market (“LCM”). We capitalize, as a cost of inventory,
shipping and handling charges associated with such purchase volumes, terminal
storage fees, vessel inspection costs, demurrage charges and other related
costs. As volumes are sold and delivered out of inventory, the cost
of these volumes (including freight-in charges that have been capitalized as
part of inventory cost) are charged to operating costs and
expenses. Shipping and handling fees associated with products we sell
and deliver to customers are charged to operating costs and expenses as
incurred. See Note 6 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
December 31, 2009:
|
Natural
gas imbalance receivables (1)
|
$ | 24.1 | ||
|
Natural
gas imbalance payables (2)
|
19.0 | |||
|
(1)
Reflected
as a component of “Accounts and notes receivable – trade” on our
Consolidated Balance Sheet.
(2) Reflected
as a component of “Accrued product payables” on our Consolidated Balance
Sheet.
|
||||
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 and 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 is 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, 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 or processing 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. See Note 7 for additional information regarding our property,
plant and equipment.
Certain of our plant operations entail
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
our planned major maintenance activities; however, the cost of annual planned
major maintenance projects are deferred and recognized ratably over the
remaining portion of the calendar year in which such projects
occur.
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.
Restricted
Cash
Restricted
cash represents amounts held in connection with our commodity derivative
instruments portfolio and related physical natural gas and NGL
purchases. Additional cash may be restricted to maintain this
portfolio as commodity prices fluctuate or deposit requirements
change. At December 31, 2009, our restricted cash amount was $63.6
million. See Note 5 for information regarding derivative instruments
and hedging activities.
The
accounting standard setting bodies have recently issued the following guidance
that will or may affect our future balance sheet:
Fair
Value Measurements. In January 2010, the
Financial Accounting Standards Board (“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 Balance
Sheet.
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 Balance Sheet.
The fair value of an equity-classified
award (e.g., a restricted unit award) is amortized to earnings on a
straight-line basis over the requisite service or vesting
period. Compensation expense for liability-classified awards (e.g.,
unit appreciation rights (“UARs”)) is recognized over the requisite service or
vesting period of an award based on the fair value of the award remeasured at
each reporting period. Liability-classified awards are settled in
cash upon vesting.
At
December 31, 2009, our active long-term incentive plans are the Enterprise
Products 1998 Long-Term Incentive Plan (“1998 Plan”), the TEPPCO 1999 Phantom
Unit Retention Plan (“1999 Plan”), the Enterprise Products 2006 TPP Long-Term
Incentive Plan (“2006 Plan”) and the Amended and Restated 2008 Enterprise
Products Long-Term Incentive Plan (“2008 Plan”). Two plans were
dissolved during
2009: TEPPCO
2000 Long-Term Incentive Plan (“2000 Plan”) and TEPPCO 2005 Phantom Unit Plan
(“2005 Plan”).
The 1998
Plan provides for awards of Enterprise Products Partners’ common units and other
rights to our 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, 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 could be
issued.
The 1999
Plan provided key employees of EPCO who work on our behalf with phantom unit
awards. This plan terminated in January 2010.
The 2006
Plan currently provides for awards of Enterprise Products Partners’ common units
(formerly of TEPPCO units) and other rights to our non-employee directors and to
employees of EPCO and its affiliates providing services to us. Awards
under the 2006 Plan may be granted in the form of unit options, restricted
units, phantom units, UARs and DERs. Effective upon the consummation
of the TEPPCO Merger (see Note 1), Enterprise Products Partners assumed the
vested and unvested options, restricted units and UAR awards outstanding on
October 26, 2009 under the 2006 Plan and converted them into Enterprise Products
Partners’ options, restricted units and UAR awards based on the TEPPCO Merger
exchange ratio. The vesting terms of each award and other provisions
of the plan remain unchanged.
The
2008 Plan provides for awards of Enterprise Products Partners’ common units and
other rights to our 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 could be
issued.
An
allocated portion of the fair value of these long-term incentive plan
equity-based awards is charged to us under the administrative services agreement
(“ASA”). See Note 14 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 expenses associated with such awards. We
recognize an expense for our allocated share of the grant date fair value of
such awards, with an offsetting amount recorded in equity. 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.
On
December 10, 2009, the board of directors of DEP GP unanimously approved a
resolution adopting both the 2010 Duncan Energy Partners L.P. Long-Term
Incentive Plan (“2010 Plan”) and the DEP Unit Purchase Plan (“DEP EUPP”).
The 2010 Plan provides for awards of options to purchase Duncan Energy Partners’
common units, restricted common units, UARs, phantom units and DERs to
employees, directors or consultants providing services to Duncan Energy
Partners. The DEP 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 of directors of DEP GP regarding the plans was approved by written consent
of EPO, which held approximately 58.6% of Duncan Energy Partners’ outstanding
common units as of that date. Because EPO held a majority of Duncan
Energy Partners’ common units as of December 30, 2009, no other votes were
necessary to adopt the plans. In February 2010, Duncan Energy Partners
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 DEP EUPP. The plans became effective on February
11, 2010.
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. As used in the
context of our 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 our restricted unit awards for
the year ended December 31, 2009:
|
Weighted-
|
||||||||
|
Average
Grant
|
||||||||
|
Number
of
|
Date
Fair Value
|
|||||||
|
Units
|
per Unit
(1)
|
|||||||
|
Restricted
units at December 31, 2008
|
2,080,600 | $ | 29.09 | |||||
|
Granted
(2)
|
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 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.
|
||||||||
The total
fair value of restricted unit awards that vested during the year ended December
31, 2009 was $7.5 million.
Unit
Option Awards
Certain
of our long-term incentive plans provide for the issuance of non-qualified
incentive options to purchase a fixed number of Enterprise Products Partners’
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 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 Enterprise Products Partners’ historical unit price volatility and
distribution yield over a period equal to the expected life of the
option.
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. When employees exercise unit options, Enterprise Products
Partners reimburses EPCO for the cash difference between the strike price paid
by the employee and the actual purchase price paid by EPCO for the units issued
to the employee.
The
following table presents unit option activity under the EPCO plans for the year
ended December 31, 2009:
|
Weighted-
|
||||||||||||||||
|
Weighted-
|
Average
|
|||||||||||||||
|
Average
|
Remaining
|
Aggregate
|
||||||||||||||
|
Number
of
|
Strike
Price
|
Contractual
|
Intrinsic
|
|||||||||||||
|
Units
|
(dollars/unit)
|
Term
(in years)
|
Value
(1)
|
|||||||||||||
|
Outstanding
at December 31, 2008
|
2,963,500 | 27.56 | ||||||||||||||
|
Granted
(2)
|
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 (3)
|
3,825,920 | 26.52 | 4.6 | $ | 2.8 | |||||||||||
|
Options
exercisable at:
|
||||||||||||||||
|
December
31, 2009 (3)
|
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 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% was applied to awards
granted during 2009.
(3)
We
were committed to issue 3,825,920 of Enterprise Products Partners’ common
units at December 31, 2009, if all outstanding options awarded (as of this
date) 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.
|
||||||||||||||||
The
following table presents supplemental information regarding Enterprise Products
Partners’ unit options for the year ended December 31, 2009:
|
Total
intrinsic value of option awards exercised during period
|
$ | 2.4 | ||
|
Cash
received from EPCO in connection with the exercise
of unit option awards
|
1.7 | |||
|
Option-related
reimbursements to EPCO
|
2.4 |
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 private company affiliates of EPCO. At December 31, 2009,
the Employee Partnerships are EPE Unit I, EPE Unit II, EPE Unit III, Enterprise
Unit and EPCO Unit. TEPPCO Unit L.P. and TEPPCO Unit II L.P. were
dissolved during 2009.
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
|
|||
|
Employee
|
Description
|
Capital
|
Preferred
|
Liquidation
|
Fair
Value
|
|
Partnership
|
of
Assets
|
Base
|
Return
|
Date (1)
|
of
Awards
|
|
EPE
Unit I
|
1,821,428
EPE units
|
$51.0
million
|
4.50%
to 5.725%
|
February
2016
|
$21.5
million
|
|
EPE
Unit II
|
40,725
EPE units
|
$1.5
million
|
4.50%
to 5.725%
|
February
2016
|
$0.4
million
|
|
EPE
Unit III
|
4,421,326
EPE units
|
$170.0
million
|
3.80%
|
February
2016
|
$42.8
million
|
|
Enterprise
Unit
|
881,836
EPE units
844,552
EPD units
|
$51.5
million
|
5.00%
|
February
2016
|
$6.5
million
|
|
EPCO
Unit
|
779,102
EPD units
|
$17.0
million
|
4.87%
|
February
2016
|
$8.1
million
|
|
(1)
The
liquidation date may be accelerated for change of control and other events
as described in the underlying partnership
agreements.
|
|||||
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 year ended December 31, 2009.
|
Aggregate
grant date fair values at beginning of period
|
$ | 64.6 | ||
|
Award
modifications
|
19.5 | |||
|
Other
adjustments, primarily forfeiture and regrant activity (1)
|
(4.8 | ) | ||
|
Aggregate
grant date fair value at end of period
|
$ | 79.3 | ||
|
(1)
TEPPCO
Unit and TEPPCO Unit II were dissolved during 2009.
|
||||
The
following table summarizes the assumptions we 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%
|
Phantom
Units
Certain
of our long-term incentive plans provide for the issuance of phantom unit
awards. These awards are automatically redeemed for cash based on the
fair value of the vested portion of phantom units at redemption dates in each
award. The fair value of each phantom unit award is equal to the
closing market price of the underlying security on the redemption
date. Each participant is required to redeem their phantom units as
they vest, which typically is three to four years from the date the award is
granted. Our phantom units are accounted for as liability
awards.
Certain
of our long-term incentive plans also provide for the award of DERs in tandem
with phantom unit awards. A DER entitles the participant to cash
distributions equal to the product of the number of awards outstanding for the
participant and the cash distribution rate per unit paid by the issuer to its
unitholders. Such amounts are expensed when paid.
The
following table presents additional information regarding our phantom unit
awards for the year ended December 31, 2009:
|
Phantom
Unit Awards Issued by
|
||||||||||||
|
TEPPCO
|
Enterprise
Products
Partners
|
Total
|
||||||||||
|
Phantom
units at December 31, 2008
|
69,335 | 4,400 | 73,735 | |||||||||
|
Granted
|
124 | 6,200 | 6,324 | |||||||||
|
Vested
|
(61,519 | ) | -- | (61,519 | ) | |||||||
|
Settled
or forfeited
|
(4,447 | ) | -- | (4,447 | ) | |||||||
|
Awards
assumed in connection with TEPPCO Merger
|
(3,493 | ) | 4,327 | 834 | ||||||||
|
Phantom
units at December 31, 2009
|
-- | 14,927 | 14,927 | |||||||||
At
December 31, 2009, we had an accrued liability of $0.2 million related to our
phantom unit awards. During the year ended December 31, 2009 we paid
liabilities of $1.2 million related to our phantom unit awards.
At
December 31, 2009, only the 2008 Plan and the 1999 Plan had significant phantom
units outstanding. These awards will settle as
follows: 4,327 in 2010, 4,400 in 2011 and 6,200 in
2012. The 2000 Plan and 2005 Plan also issued phantom units, all of
which had vested and settled prior to December 31, 2009. The 3,472
phantom units outstanding under the 1999 Plan were settled in January 2010 and
the plan terminated.
Unit
Appreciation Rights
UARs entitle a participant to receive a
cash payment on the vesting date equal to the excess, if any, of the fair market
value of the underlying security (determined as of a future vesting date) over
the grant date fair value of the award. UARs are accounted for as
liability awards.
The
following table presents additional information regarding our UARs for the year
ended December 31, 2009:
|
UARs
Issued by
|
||||||||||||||||
|
TEPPCO
|
Enterprise
Products
Partners
|
EPE
|
Total
|
|||||||||||||
|
UARs
at December 31, 2008
|
431,377 | -- | 90,000 | 521,377 | ||||||||||||
|
Settled
or forfeited
|
(166,217 | ) | (186,614 | ) | -- | (352,831 | ) | |||||||||
|
Awards
assumed in connection with the TEPPCO Merger
|
(265,160 | ) | 328,810 | -- | 63,650 | |||||||||||
|
UARs
at December 31, 2009
|
-- | 142,196 | 90,000 | 232,196 | ||||||||||||
At December 31, 2009, we had an accrued
liability of $0.3 million related to our UARs.
At
December 31, 2009, 142,196 UARs had been granted under the 2006 Plan to certain
employees of EPCO who work on our behalf. These awards are subject to
five year cliff vesting requirements and are expected to settle in
2012. The grant date fair value with respect to these UARs is based
on an Enterprise Products Partners’ unit price of $37.00. If the
employee resigns prior to vesting, these UAR awards are forfeited.
Prior to
the TEPPCO Merger, 95,654 UARs had been granted to the non-employee former
directors of TEPPCO under the 2006 Plan. The awards were settled in
October 2009 and $0.1 million in cash was paid to the former
directors.
The
non-employee directors of DEP GP, the general partner of Duncan Energy Partners,
have been granted UARs in the form of letter agreements. These
liability awards are not part of any established long-term incentive plan of
EPCO, Enterprise GP Holdings, Duncan Energy Partners or Enterprise Products
Partners. The compensation expense associated with these awards is
recognized by DEP GP, which is our consolidated subsidiary. At
December 31, 2009, there were a total of 90,000 outstanding UARs granted to
non-employee directors of DEP GP that cliff vest in 2012. If a
director resigns prior to vesting, his UAR awards are forfeited. The
grant date fair value with respect to these UARs is based on an Enterprise GP
Holdings’ unit price of $36.68.
In the
course of our normal business operations, we are exposed to certain risks,
including changes in interest rates, commodity prices and, to a limited extent,
foreign exchange rates. 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. 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.
|
|
§
|
Variable
cash flows of a forecasted
transaction.
|
|
§
|
Foreign
currency exposure.
|
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. 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.
Interest
Rate Derivative Instruments
We utilize interest rate swaps,
treasury locks and similar derivative instruments 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
and Type of
|
Notional
|
Period
of
|
Rate
|
Accounting
|
|
|
Hedged
Transaction
|
Derivative
Employed
|
Amount
|
Hedge
|
Swap
|
Treatment
|
|
Enterprise
Products Partners:
|
|||||
|
Senior
Notes C
|
1
fixed-to-floating swap
|
$100.0
|
1/04
to 2/13
|
6.4%
to 2.8%
|
Fair
value hedge
|
|
Senior
Notes G
|
3
fixed-to-floating swaps
|
$300.0
|
10/04
to 10/14
|
5.6%
to 1.5%
|
Fair
value hedge
|
|
Senior Notes P
|
7
fixed-to-floating swaps
|
$400.0
|
6/09
to 8/12
|
4.6%
to 2.7%
|
Fair
value hedge
|
|
Duncan
Energy Partners:
|
|||||
|
Variable-interest
rate borrowings
|
3
floating-to-fixed swaps
|
$175.0
|
9/07
to 9/10
|
0.3%
to 4.6%
|
Cash
flow hedge
|
At times,
we may use treasury lock derivative instruments to hedge the underlying U.S.
treasury rates related to forecasted issuances of debt.
During
the year ended December 31, 2009, we entered into four forward starting interest
rate swaps to hedge the underlying benchmark interest payments related to the
forecasted issuances of debt.
|
Number
and Type of
|
Notional
|
Period
of
|
Average
Rate
|
Accounting
|
|
|
Hedged
Transaction
|
Derivative
Employed
|
Amount
|
Hedge
|
Locked
|
Treatment
|
|
Future
debt offering
|
1
forward starting swap
|
$50.0
|
6/10
to 6/20
|
3.3%
|
Cash
flow hedge
|
|
Future
debt offering
|
3
forward starting swaps
|
$250.0
|
2/11
to 2/21
|
3.6%
|
Cash
flow hedge
|
Forward
starting interest rate swaps are used to hedge the underlying benchmark interest
payments related to the forecasted issuances of debt. The fair market
value of the forward starting swaps was $21.0 million at December 31,
2009. During January and February 2010, we entered into five
additional forward starting swaps with a notional amount of $50.0 million
each. The period hedged by these five forward starting swaps is
February 2012 through February 2022.
Commodity
Derivative Instruments
The prices of natural gas, NGLs, crude
oil, refined products and certain petrochemical products are 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, futures and
options contracts. The following table summarizes our commodity
derivative instruments outstanding at December 31, 2009:
|
Volume
(1)
|
Accounting
|
||
|
Derivative
Purpose
|
Current
|
Long-Term
(2)
|
Treatment
|
|
Derivatives
designated as hedging instruments:
|
|||
|
Enterprise
Products Partners:
|
|||
|
Natural
gas processing:
|
|||
|
Forecasted
natural gas purchases for plant thermal reduction (“PTR”)
(3)
|
17.8
Bcf
|
n/a
|
Cash
flow hedge
|
|
Forecasted
NGL sales (4)
|
2.4
MMBbls
|
n/a
|
Cash
flow hedge
|
|
Octane
enhancement:
|
|||
|
Forecasted
purchases of NGLs
|
2.0
MMBbls
|
n/a
|
Cash
flow hedge
|
|
NGLs
inventory management
|
0.1
MMBbls
|
n/a
|
Cash
flow hedge
|
|
Forecasted
sales of octane enhancement products
|
3.4
MMBbls
|
0.4
MMBbls
|
Cash
flow hedge
|
|
Natural
gas marketing:
|
|||
|
Natural
gas storage inventory management activities
|
3.5
Bcf
|
n/a
|
Fair
value hedge
|
|
NGL
marketing:
|
|||
|
Forecasted
purchases of NGLs and related hydrocarbon products
|
7.5
MMBbls
|
n/a
|
Cash
flow hedge
|
|
Forecasted
sales of NGLs and related hydrocarbon products
|
8.0
MMBbls
|
n/a
|
Cash
flow hedge
|
|
Derivatives
not designated as hedging instruments:
|
|||
|
Enterprise
Products Partners:
|
|||
|
Natural
gas risk management activities (5) (6)
|
359.2
Bcf
|
33.9
Bcf
|
Mark-to-market
|
|
NGL
risk management activities (6)
|
0.4
MMBbls
|
n/a
|
Mark-to-market
|
|
Crude
oil risk management activities (6)
|
3.5
MMBbls
|
n/a
|
Mark-to-market
|
|
Duncan
Energy Partners:
|
|||
|
Natural
gas risk management activities (6)
|
2.2
Bcf
|
n/a
|
Mark-to-market
|
|
(1)
Volume
for derivatives designated as hedging instruments reflects the total
amount of volumes hedged whereas volume for derivatives not designated as
hedging instruments reflects the absolute value of derivative notional
volumes.
(2)
The
maximum term for derivatives included in the long-term column is December
2012.
(3)
PTR
represents the British thermal unit equivalent of the NGLs extracted from
natural gas by a processing plant, and includes the natural gas used as
plant fuel to extract those liquids, plant flare and other
shortages. See the discussion below for the primary objective
of this strategy.
(4)
Excludes
5.4 MMBbls of additional hedges executed under contracts that have been
designated as normal sales agreements under the FASB’s derivative and
hedging guidance. The combination of these volumes with the 2.4
MMBbls reflected as derivatives in the table above results in a total of
7.8 MMBbls of hedged forecasted NGL sales volumes, which corresponds to
the 17.8 Bcf of forecasted natural gas purchase volumes for
PTR.
(5)
Current
and long-term volumes include approximately 109.5 and 12.6 billion cubic
feet (“Bcf”), respectively, of physical derivative instruments that are
predominantly priced at an index plus a premium or minus a
discount.
(6)
Reflects
the use of derivative instruments to manage risks associated with
transportation, processing and storage
assets.
|
|||
Certain of our derivative instruments
do not meet hedge accounting requirements; therefore, they are accounted for
using mark-to-market accounting.
Our three predominant hedging
strategies are hedging natural gas processing margins, hedging anticipated
future sales of NGLs, refined products and crude oil associated with volumes
held in inventory and hedging the fair value of natural gas in
inventory. The objective of our natural gas processing strategy is to
hedge an amount of gross margin associated with the gas processing activities.
We achieve this by using physical and financial instruments to lock in the
prices of natural gas purchases used for PTR and NGL sales. This
program consists of (i) the forward sale of a portion of our expected equity NGL
production
at fixed prices through December 2010, achieved through the use of forward
physical sales and commodity derivative instruments and (ii) the purchase of
commodity derivative instruments with a notional amount determined by the amount
of natural gas expected to be consumed as PTR in the production of such equity
NGL production. The objective of our NGL, refined products and crude
oil sales hedging program is to hedge anticipated future sales of inventory by
locking in the sales price through the use of forward physical sales and
commodity derivative instruments. The objective of our natural gas
inventory hedging program is to hedge the fair value of natural gas currently
held in inventory by locking in the sales price of the inventory through the use
of commodity derivative instruments.
Foreign
Currency Derivative Instruments
We are exposed to a nominal amount of
foreign currency exchange risk in connection with our NGL and natural gas
marketing activities in Canada. As a result, we could be adversely
affected by fluctuations in currency rates between the U.S. dollar and Canadian
dollar. In order to manage this risk, we may enter into foreign
exchange purchase contracts to lock in the exchange rate. These
long-term transactions (more than two months) are accounted for as cash flow
hedges. Shorter term transactions are accounted for using
mark-to-market accounting.
In 2009 we were exposed to foreign
currency exchange risk in connection with a term loan denominated in Japanese
yen. We entered into this loan agreement in November 2008 and the
loan matured in March 2009. The derivative instrument used to hedge
this risk was accounted for as a cash flow hedge and was settled upon repayment
of the loan.
At
December 31, 2009, we had foreign currency derivative instruments outstanding
with a notional amount of $4.1 million Canadian dollars. The fair
market value of these instruments was an asset of $0.2 million at December 31,
2009.
Credit-Risk
Related Contingent Features in Derivative Instruments
A
limited number of our commodity derivative instruments include provisions
related to credit ratings and/or adequate assurance clauses. A credit
rating provision provides for a counterparty to demand immediate full or partial
payment to cover a net liability position upon the loss of a stipulated credit
rating. An adequate assurance clause provides for a counterparty to
demand immediate full or partial payment to cover a net liability position
should reasonable grounds for insecurity arise with respect to contractual
performance by either party. At December 31, 2009, the aggregate fair
value of our over-the-counter derivative instruments in a net liability position
was $7.7 million, approximately $6.1 million of which was subject to a credit
rating contingent feature. If our credit ratings were downgraded to
Ba2/BB, approximately $1.1 million would be payable as a margin deposit to the
counterparties, and if our credit ratings were downgraded to Ba3/BB- or below,
approximately $6.1 million would be payable as a margin deposit to the
counterparties. Currently, no margin is required to be
deposited. 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 of Derivative Instruments and Related Hedged
Items
The
following table provides a balance sheet overview of our derivative assets and
liabilities at December 31, 2009:
|
Asset
Derivatives
|
Liability
Derivatives
|
|||||||||
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
|||||||
|
Location
|
Value
|
Location
|
Value
|
|||||||
|
Derivatives designated
as hedging instruments
|
||||||||||
|
Interest
rate derivatives
|
Derivative
assets
|
$ | 32.7 |
Derivative
liabilities
|
$ | 5.5 | ||||
|
Interest
rate derivatives
|
Other
assets
|
31.8 |
Other
liabilities
|
2.2 | ||||||
|
Total
interest rate derivatives
|
64.5 | 7.7 | ||||||||
|
Commodity
derivatives
|
Derivative
assets
|
52.0 |
Derivative
liabilities
|
62.6 | ||||||
|
Commodity
derivatives
|
Other
assets
|
0.5 |
Other
liabilities
|
1.8 | ||||||
|
Total
commodity derivatives (1)
|
52.5 | 64.4 | ||||||||
|
Foreign
currency derivatives (2)
|
Derivative
assets
|
0.2 |
Derivative
liabilities
|
-- | ||||||
|
Total
derivatives designated as hedging
instruments
|
$ | 117.2 | $ | 72.1 | ||||||
|
Derivatives not
designated as hedging instruments
|
||||||||||
|
Commodity
derivatives
|
Derivative
assets
|
$ | 28.9 |
Derivative
liabilities
|
$ | 24.9 | ||||
|
Commodity
derivatives
|
Other
assets
|
2.0 |
Other
liabilities
|
2.7 | ||||||
|
Total
commodity derivatives
|
30.9 | 27.6 | ||||||||
|
Foreign
currency derivatives
|
Derivative
assets
|
-- |
Derivative
liabilities
|
-- | ||||||
|
Total
derivatives not designated as hedging
instruments
|
$ | 30.9 | $ | 27.6 | ||||||
|
(1)
Represents
commodity derivative transactions that either have not settled or have
settled and not been invoiced. Settled and invoiced transactions are
reflected in either accounts receivable or accounts payable depending on
the outcome of the transaction.
(2)
Relates
to the hedging of our exposure to fluctuations in the foreign currency
exchange rate related to our Canadian NGL marketing
subsidiary.
|
||||||||||
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 on the balance sheet 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 derivative
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 derivative 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. The
value of 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. Our Level 3 fair values largely consist of ethane,
normal butane and natural gasoline-based contracts with a range of two to
12 months in term. We rely on price quotes from reputable
brokers in the marketplace who publish price quotes on certain
products. Whenever possible, we compare these prices to other
reputable brokers for the same product in the same
market. These prices, combined with our forward transactions,
are used in our model to determine the fair value of such
instruments.
|
The
following table set forth, by level within the fair value hierarchy, our
financial assets and liabilities measured on a recurring basis at December 31,
2009. 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.
|
Level
1
|
Level
2
|
Level
3
|
Total
|
|||||||||||||
|
Financial
assets:
|
||||||||||||||||
|
Interest
rate derivative instruments
|
$ | -- | $ | 64.5 | $ | -- | $ | 64.5 | ||||||||
|
Commodity
derivative instruments
|
14.6 | 34.4 | 34.4 | 83.4 | ||||||||||||
|
Foreign
currency derivative instruments
|
-- | 0.2 | -- | 0.2 | ||||||||||||
|
Total
|
$ | 14.6 | $ | 99.1 | $ | 34.4 | $ | 148.1 | ||||||||
|
Financial
liabilities:
|
||||||||||||||||
|
Interest
rate derivative instruments
|
$ | -- | $ | 7.7 | $ | -- | $ | 7.7 | ||||||||
|
Commodity
derivative instruments
|
17.1 | 46.2 | 28.7 | 92.0 | ||||||||||||
|
Total
|
$ | 17.1 | $ | 53.9 | $ | 28.7 | $ | 99.7 | ||||||||
The
following table sets forth a reconciliation of changes in the fair value of our
Level 3 financial assets and liabilities for the year ended December 31,
2009:
|
Balance,
January 1
|
$ | 32.4 | ||
|
Total
gains (losses) included in:
|
||||
|
Net
income
|
27.0 | |||
|
Other
comprehensive income (loss)
|
(21.8 | ) | ||
|
Purchases,
issuances, settlements
|
(26.8 | ) | ||
|
Transfer
out of Level 3
|
(5.1 | ) | ||
|
Balance,
December 31
|
$ | 5.7 |
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 (see Note 7)
|
$ | 29.6 | $ | 29.4 | ||||
|
Intangible
assets (see Note 10)
|
0.6 | 0.6 | ||||||
|
Goodwill
(see Note 10)
|
-- | 1.3 | ||||||
|
Other
current assets
|
1.2 | 2.2 | ||||||
|
Total
|
$ | 31.4 | $ | 33.5 | ||||
Using
appropriate valuation techniques, we adjusted the carrying value of certain
assets to $31.4 million and recorded non-cash impairment charges of $33.5
million during 2009. These charges have been allocated to property,
plant and equipment, intangible assets, goodwill and other current
assets. During 2009, impairments primarily resulted from (i) reduced
levels of throughput volumes at certain river terminals and the indefinite
suspension of three new proposed river terminals, (ii) reduced throughput levels
at a natural gas processing plant, (iii) the cancellation of a compressor
station project and (iv) the determination that a storage cavern and certain
marine barges were obsolete. Our fair value estimates were based
primarily on an evaluation of the future cash flows associated with each
asset.
Our
inventory amounts were as follows at December 31, 2009:
|
Working
inventory (1)
|
$ | 466.4 | ||
|
Forward
sales inventory (2)
|
245.5 | |||
|
Total
inventory
|
$ | 711.9 | ||
|
(1)
Working
inventory is comprised of inventories of natural gas, NGLs, crude oil,
refined products, lubrication oils and certain petrochemical products that
are either available-for-sale or used in the provision for
services.
(2)
Forward
sales inventory consists of identified natural gas, NGL, refined product
and crude oil volumes dedicated to the fulfillment of forward sales
contracts. In general, the increase in volumes dedicated to forward
physical sales contracts improves the overall utilization and
profitability of our fee-based assets. The cash invested in forward
sales NGL inventories is expected to be recovered within the next twelve
months as physical delivery from inventory occurs.
|
||||
In
those instances where we take ownership of inventory volumes through
percent-of-liquids contracts and similar arrangements (as opposed to actually
purchasing volumes for cash from third parties), these volumes are valued at
market-based prices during the month in which they are acquired.
Due to
fluctuating commodity prices, we recognize LCM adjustments when the carrying
value of our inventories exceeds their net realizable value.
To the
extent our commodity hedging strategies address inventory-related risks and are
successful, these inventory valuation adjustments are mitigated or
offset. See Note 5 for a description of our commodity hedging
activities.
Our
property, plant and equipment values and accumulated depreciation balance were
as follows at December 31, 2009:
|
Estimated
|
||||||||
|
Useful
Life
|
||||||||
|
in
Years
|
||||||||
|
Plants
and pipelines (1)
|
3-45 (5) | $ | 17,681.9 | |||||
|
Underground
and other storage facilities (2)
|
5-40 (6) | 1,280.5 | ||||||
|
Platforms
and facilities (3)
|
20-31 | 637.6 | ||||||
|
Transportation
equipment (4)
|
3-10 | 60.1 | ||||||
|
Marine
vessels
|
20-30 | 559.4 | ||||||
|
Land
|
82.9 | |||||||
|
Construction
in progress
|
1,207.2 | |||||||
|
Total
|
21,509.6 | |||||||
|
Less
accumulated depreciation
|
3,820.4 | |||||||
|
Property,
plant and equipment, net
|
$ | 17,689.2 | ||||||
|
(1)
Plants
and pipelines include processing plants; NGL, petrochemical, crude oil and
natural gas pipelines; terminal loading and unloading facilities; office
furniture and equipment; buildings; laboratory and shop equipment and
related assets.
(2)
Underground
and other storage facilities include underground product storage caverns;
above ground storage tanks; water wells and related assets.
(3)
Platforms
and facilities include offshore platforms and related facilities and other
associated assets.
(4)
Transportation
equipment includes vehicles and similar assets used in our
operations.
(5)
In
general, the estimated useful lives of major components of this category
are as follows: processing plants, 20-35 years; pipelines and related
equipment, 5-45 years; terminal facilities, 10-35 years; delivery
facilities, 20-40 years; office furniture and equipment, 3-20 years;
buildings, 20-40 years; and laboratory and shop equipment, 5-35
years.
(6)
In
general, the estimated useful lives of major components of this category
are as follows: underground storage facilities, 5-35 years; storage
tanks, 10-40 years; and water wells, 5-35 years.
|
||||||||
In August
2008, our wholly owned subsidiaries, together with Oiltanking Holding Americas,
Inc. (“Oiltanking”) formed the Texas Offshore Port System partnership
(“TOPS”). Effective April 16, 2009, our wholly owned subsidiaries
dissociated from TOPS.
TOPS was
a consolidated subsidiary of ours prior to the dissociation. The
effect of deconsolidation was to remove the accounts of TOPS, including
Oiltanking’s noncontrolling interest of $33.4 million, from our books and
records, after reflecting the $68.4 million aggregate write-off of the
investment.
We
recorded $53.1 million in capitalized interest during the year ended December
31, 2009.
In
addition, we recorded $21.0 million, $4.3 million and $4.1 million of non-cash
asset impairment charges within our Petrochemical & Refined Products
Services segment, Onshore Natural Gas Pipelines & Services segment and NGL
Pipelines & Services segment, respectively, related to plant, property and
equipment during the year ended December 31, 2009. See Note 5 for
additional information regarding impairment charges.
Asset
Retirement Obligations
We have
recorded AROs related to legal requirements to perform retirement activities as
specified in contractual arrangements and/or governmental
regulations. In general, our AROs primarily result from (i)
right-of-way agreements associated with our pipeline operations, (ii) leases of
plant sites and (iii) regulatory requirements triggered by the abandonment or
retirement of certain underground storage assets and offshore
facilities. In addition, our AROs may result from the renovation or
demolition of certain assets containing hazardous substances such as
asbestos.
The
following table presents information regarding our AROs since December 31,
2008:
|
ARO
liability balance, December 31, 2008
|
$ | 42.2 | ||
|
Liabilities
incurred
|
0.5 | |||
|
Liabilities
settled
|
(17.1 | ) | ||
|
Revisions
in estimated cash flows
|
26.1 | |||
|
Accretion
expense
|
3.1 | |||
|
ARO
liability balance, December 31, 2009
|
$ | 54.8 |
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 offshore facilities in the Gulf of Mexico.
Property,
plant and equipment at December 31, 2009 includes $26.7 million of asset
retirement costs capitalized as an increase in the associated long-lived
asset.
Certain
of our unconsolidated affiliates have AROs recorded at December 31, 2009
relating to contractual agreements and regulatory requirements. These
amounts are immaterial to our Consolidated Balance Sheet.
We own
interests in a number of related businesses that are accounted for using the
equity method of accounting. We group our investments in
unconsolidated affiliates according to the business segment to which they relate
(see Note 13 for a general discussion of our business segments). The
following table shows our investments in unconsolidated affiliates by business
segment at December 31, 2009:
|
Ownership
|
||||||||
|
Percentage
|
||||||||
|
NGL
Pipelines & Services:
|
||||||||
|
Venice
Energy Service Company, L.L.C.
|
13.1% | $ | 32.6 | |||||
|
K/D/S
Promix, L.L.C.
|
50% | 48.9 | ||||||
|
Baton
Rouge Fractionators LLC
|
32.2% | 22.2 | ||||||
|
Skelly-Belvieu
Pipeline Company, L.L.C.
|
49% | 37.9 | ||||||
|
Onshore
Natural Gas Pipelines & Services:
|
||||||||
|
Evangeline
(1)
|
49.5% | 5.6 | ||||||
|
White
River Hub, LLC
|
50% | 26.4 | ||||||
|
Onshore
Crude Oil Pipelines & Services:
|
||||||||
|
Seaway
Crude Pipeline Company
|
50% | 178.5 | ||||||
|
Offshore
Pipelines & Services:
|
||||||||
|
Poseidon
Oil Pipeline, L.L.C.
|
36% | 61.7 | ||||||
|
Cameron
Highway Oil Pipeline Company (“Cameron Highway”)
|
50% | 239.6 | ||||||
|
Deepwater
Gateway, L.L.C.
|
50% | 101.8 | ||||||
|
Neptune
Pipeline Company, L.L.C.
|
25.7% | 53.8 | ||||||
|
Nemo
Gas Gathering Company, LLC (“Nemo”)
|
33.9% | -- | ||||||
|
Petrochemical
& Refined Products Services:
|
||||||||
|
Baton
Rouge Propylene Concentrator, LLC
|
30% | 11.1 | ||||||
|
Centennial
Pipeline LLC (“Centennial”)
|
50% | 66.7 | ||||||
|
Other
(2)
|
Varies
|
3.8 | ||||||
|
Total
|
$ | 890.6 | ||||||
|
|
||||||||
|
(1)
Evangeline
refers to our ownership interests in Evangeline Gas Pipeline Company, L.P.
and Evangeline Gas Corp., collectively.
(2)
Other
unconsolidated affiliates include a 50% interest in a propylene pipeline
extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest
in a company that provides logistics communications solutions between
petroleum pipelines and their customers.
|
||||||||
On
occasion, the price we pay to acquire an ownership interest in a company exceeds
the underlying book value of the capital accounts we acquire. Such
excess cost amounts are included within the carrying values of our investments
in unconsolidated affiliates. The following table summarizes the
unamortized excess cost amounts by business segment at December 31,
2009:
|
NGL
Pipelines & Services
|
$ | 27.1 | ||
|
Onshore
Crude Oil Pipelines & Services
|
20.4 | |||
|
Offshore
Pipelines & Service
|
17.3 | |||
|
Petrochemical
& Refined Products Services
|
4.0 | |||
|
Total
|
$ | 68.8 |
NGL
Pipelines & Services
At
December 31, 2009, our investees included in our NGL Pipelines & Services
segment own: (i) a natural gas processing facility and related assets located in
south Louisiana, (ii) an NGL fractionation facility and related storage and
pipeline assets located in south Louisiana, (iii) an NGL fractionation facility
located in south Louisiana and (iv) a 572-mile pipeline that transports mixed
NGLs to markets in southeast Texas.
Onshore
Natural Gas Pipelines & Services
At December 31, 2009, our investees
included in our Onshore Natural Gas Pipelines & Services segment own: (i) a
natural gas pipeline located in south Louisiana and (ii) a natural gas hub
located in northwest Colorado that commenced operations in December
2008.
Onshore
Crude Oil Pipelines & Services
At
December 31, 2009, our investee included in our Onshore Crude Oil Pipelines
& Services segment owns a pipeline
that transports crude oil from a marine terminal located in Freeport, Texas, to
Cushing, Oklahoma, and from a marine terminal located in Texas City, Texas, to
refineries in the Texas City and Houston, Texas areas.
Offshore
Pipelines & Services
At
December 31, 2009, our investees included in our Offshore Pipelines &
Services segment own: (i) a crude oil pipeline that gathers
production from the outer continental shelf and deepwater areas of the Gulf of
Mexico for delivery to onshore locations in south Louisiana, (ii) a crude oil
pipeline that gathers production from deepwater areas of the Gulf of Mexico,
primarily the South Green Canyon area, for delivery to refineries and terminals
in southeast Texas, (iii) a crude oil and natural gas platform that processes
production from the Marco Polo, K2, K2 North and Genghis Khan fields located in
the South Green Canyon area of the Gulf of Mexico and (iv) natural gas pipeline
systems located in the Gulf of Mexico.
Petrochemical
& Refined Products Services
At
December 31, 2009, the investees included in our Petrochemical & Refined
Products Services segment own: (i) a propylene fractionation facility located in
south Louisiana, (ii) a propylene pipeline extending from Mont Belvieu, Texas to
La Porte, Texas and (iii) an interstate refined products pipeline extending from
the upper Texas Gulf Coast to central Illinois that effectively loops our
refined products pipeline system providing incremental transportation capacity
into Mid-continent markets.
Summarized
Combined Financial Information of Unconsolidated Affiliates
The
combined balance sheet information at December 31, 2009 is summarized
below:
|
Current
assets
|
$ | 201.0 | ||
|
Property,
plant and equipment, net
|
1,997.2 | |||
|
Other
assets
|
36.4 | |||
|
Total
assets
|
$ | 2,234.6 | ||
|
Current
liabilities
|
$ | 118.6 | ||
|
Other
liabilities
|
255.4 | |||
|
Combined
equity
|
1,860.6 | |||
|
Total
liabilities and combined equity
|
$ | 2,234.6 |
The
following table presents our cash used for business combinations by segment for
the year ended December 31, 2009:
|
NGL
Pipelines & Services
|
$ | 33.3 | ||
|
Onshore
Natural Gas Pipelines & Services
|
0.8 | |||
|
Petrochemical
& Refined Products Services
|
73.2 | |||
|
Total
cash used for business combinations
|
$ | 107.3 |
The
following table depicts the fair value allocation of assets acquired and
liabilities assumed for our business combinations for the year ended December
31, 2009:
|
Assets
acquired in business combination:
|
||||
|
Current
assets
|
$ | 1.4 | ||
|
Property,
plant and equipment, net
|
115.9 | |||
|
Intangible
assets
|
0.3 | |||
|
Other
assets
|
(0.3 | ) | ||
|
Total
assets acquired
|
117.3 | |||
|
Liabilities
assumed in business combination:
|
||||
|
Current
liabilities
|
0.3 | |||
|
Total
liabilities assumed
|
0.3 | |||
|
Total
assets acquired plus liabilities assumed
|
117.6 | |||
|
Noncontrolling
interest acquired
|
10.3 | |||
|
Total
cash used for business combinations
|
107.3 | |||
|
Goodwill
|
$ | -- | ||
Our business combinations primarily
consisted of:
|
§
|
the
acquisition of certain rail and truck terminal facilities located in Mont
Belvieu, Texas from Martin Midstream Partners LP for $23.7 million in
cash;
|
|
§
|
the
acquisition of tow boats and tank barges primarily based in Miami,
Florida, with additional assets located in Mobile, Alabama and Houston,
Texas from TransMontaigne Product Services Inc. for $50.0 million in cash;
and
|
|
§
|
the
acquisition of a majority interest in the Rio Grande Pipeline Company
(“Rio Grande”) purchased from HEP Navajo Southern L.P. for $32.8 million
in cash. Rio Grande owns an NGL pipeline system in
Texas.
|
Identifiable
Intangible Assets
The
following table summarizes our intangible assets by segment at December 31,
2009:
|
December
31, 2009
|
||||||||||||
|
Gross
|
Accum.
|
Carrying
|
||||||||||
|
Value
|
Amort.
|
Value
|
||||||||||
|
NGL
Pipelines & Services:
|
||||||||||||
|
Customer
relationship intangibles
|
$ | 237.4 | $ | (86.5 | ) | $ | 150.9 | |||||
|
Contract-based
intangibles
|
321.4 | (156.7 | ) | 164.7 | ||||||||
|
Segment
total
|
558.8 | (243.2 | ) | 315.6 | ||||||||
|
Onshore
Natural Gas Pipelines & Services:
|
||||||||||||
|
Customer
relationship intangibles
|
372.0 | (124.3 | ) | 247.7 | ||||||||
|
Contract-based
intangibles
|
565.3 | (285.8 | ) | 279.5 | ||||||||
|
Segment
total
|
937.3 | (410.1 | ) | 527.2 | ||||||||
|
Onshore
Crude Oil Pipelines & Services:
|
||||||||||||
|
Contract-based
intangibles
|
10.0 | (3.5 | ) | 6.5 | ||||||||
|
Segment
total
|
10.0 | (3.5 | ) | 6.5 | ||||||||
|
Offshore
Pipelines & Services:
|
||||||||||||
|
Customer
relationship intangibles
|
205.8 | (105.3 | ) | 100.5 | ||||||||
|
Contract-based
intangibles
|
1.2 | (0.2 | ) | 1.0 | ||||||||
|
Segment
total
|
207.0 | (105.5 | ) | 101.5 | ||||||||
|
Petrochemical & Refined
Products Services: (1)
|
||||||||||||
|
Customer
relationship intangibles
|
104.6 | (18.8 | ) | 85.8 | ||||||||
|
Contract-based
intangibles
|
42.1 | (13.9 | ) | 28.2 | ||||||||
|
Segment
total
|
146.7 | (32.7 | ) | 114.0 | ||||||||
|
Total
all segments
|
$ | 1,859.8 | $ | (795.0 | ) | $ | 1,064.8 | |||||
|
(1)
Amount
includes a non-cash impairment charge of $0.6 million in 2009 related to
certain intangible assets, see Note 5 for additional
information.
|
||||||||||||
In
general, our intangible assets fall within two categories – customer
relationship and contract-based intangible assets. The values
assigned to such intangible assets are amortized to earnings using either (i) a
straight-line approach or (ii) other methods that closely resemble the pattern
in which the economic benefits of associated resource bases are estimated to be
consumed or otherwise used, as appropriate.
Customer
relationship intangible assets. Customer relationship
intangible assets represent the estimated economic value assigned to certain
relationships acquired in connection with business combinations and asset
purchases whereby (i) we acquired information about or access to customers and
now have regular contact with them and (ii) the customers now have the ability
to make direct contact with us. Customer relationships may arise from
contractual arrangements (such as supplier contracts and service contracts) and
through means other than contracts, such as through regular contact by sales or
service representatives.
At
December 31, 2009, the carrying value of our customer relationship intangible
assets was $584.9 million. The following information summarizes the
significant components of this category of intangible assets:
|
§
|
San
Juan Gathering System customer relationships – We acquired these customer
relationships in connection with the GulfTerra Merger, which was completed
on September 30, 2004. At December 31, 2009, the carrying value
of this group of intangible assets was $220.8 million. These
intangible assets are being amortized to earnings over their estimated
economic life of 35 years through 2039. Amortization expense is
recorded using a method that closely resembles the pattern in which the
economic benefits of the underlying natural gas resource bases are
expected to be consumed or otherwise
used.
|
|
§
|
Offshore
Pipeline & Platform customer relationships – We acquired these
customer relationships in connection with the GulfTerra
Merger. At December 31, 2009, the carrying value of this group
of intangible assets was $100.5 million. These intangible
assets are being amortized to earnings over their estimated economic
lives, which range from 18 to 33 years (i.e., through 2022 to
2037). Amortization expense is recorded using a method that
closely resembles the pattern in which the economic benefits of the
underlying crude oil and natural gas resource bases are expected to be
consumed or otherwise used.
|
|
§
|
Encinal
natural gas processing customer relationship – We acquired this customer
relationship in connection with our Encinal acquisition in
2006. At December 31, 2009, the carrying value of this
intangible asset was $89.3 million. This intangible asset is
being amortized to earnings over its estimated economic life of 20 years
through 2026. Amortization expense is recorded using a method
that closely resembles the pattern in which the economic benefit of the
underlying natural gas resource bases are expected to be consumed or
otherwise used.
|
Contract-based
intangible assets. Contract-based intangible assets represent
specific commercial rights we acquired in connection with business combinations
or asset purchases. At December 31, 2009, the carrying value of our
contract-based intangible assets was $479.9 million. The following
information summarizes the significant components of this category of intangible
assets:
|
§
|
Jonah
Gas Gathering Company (“Jonah”) natural gas gathering agreements – These
intangible assets represent the value attributed to certain of Jonah’s
natural gas gathering contracts that were originally acquired by TEPPCO in
2001. At December 31, 2009, the carrying value of this group of
intangible assets was $125.0 million. These intangible assets
are being amortized to earnings using a units-of-production method based
on throughput volumes on the Jonah system, which is estimated to extend
through 2041.
|
|
§
|
Val
Verde natural gas gathering agreements – These intangible assets represent
the value attributed to certain natural gas gathering agreements
associated with our Val Verde Gathering System that was originally
acquired by TEPPCO in 2002. At December 31, 2009, the carrying
value of these intangible assets was $98.4 million. These
intangible assets are being amortized to earnings using a
units-of-production method based on throughput volumes on the Val Verde
Gathering System, which is estimated to extend through
2032.
|
|
§
|
Shell
Processing Agreement – This margin-band/keepwhole processing agreement
grants us the right to process Shell Oil Company’s (or its assignee’s)
current and future natural gas production within the state and federal
waters of the Gulf of Mexico. We acquired the Shell Processing
Agreement in connection with our 1999 purchase of certain of Shell’s
midstream energy assets located along the U.S. Gulf Coast. At
December 31, 2009, the carrying value of this intangible asset was $105.9
million. This intangible asset is being amortized to earnings
on a straight-line basis over its estimated economic life of 20 years
through 2019.
|
|
§
|
Mississippi
natural gas storage contracts – These intangible assets represent the
value assigned by us to certain natural gas storage contracts associated
with our Petal and Hattiesburg, Mississippi storage
facilities. These facilities were acquired in connection with
the GulfTerra Merger. At December 31, 2009, the carrying value
of these intangible assets was $55.4 million. These intangible
assets are being amortized to earnings on a straight-line basis over the
remainder of their respective contract terms, which range from eight to 18
years (i.e. 2012 through 2022).
|
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. The
following table presents the changes in the carrying amount of goodwill for the
year ended December 31, 2009:
|
Onshore
|
Onshore
|
Petrochemical
|
||||||||||||||||||||||
|
NGL
|
Natural
Gas
|
Crude
Oil
|
Offshore
|
&
Refined
|
||||||||||||||||||||
|
Pipelines
|
Pipelines
|
Pipelines
|
Pipelines
|
Products
|
Consolidated
|
|||||||||||||||||||
|
&
Services
|
&
Services
|
&
Services
|
&
Services
|
Services
|
Totals
|
|||||||||||||||||||
|
Balance
at December 31, 2008
|
$ | 341.2 | $ | 284.9 | $ | 303.0 | $ | 82.1 | $ | 1,008.4 | $ | 2,019.6 | ||||||||||||
|
Impairment
charges (1)
|
-- | -- | -- | -- | (1.3 | ) | (1.3 | ) | ||||||||||||||||
|
Balance
at December 31, 2009 (2)
|
$ | 341.2 | $ | 284.9 | $ | 303.0 | $ | 82.1 | $ | 1,007.1 | $ | 2,018.3 | ||||||||||||
|
(1) See
Note 5 for additional information regarding impairment charges recorded
during year ended December 31, 2009.
(2) The
total carrying amount of goodwill at December 31, 2009 is reflected net of
$1.3 million of accumulated impairment charges.
|
||||||||||||||||||||||||
Our
goodwill impairment testing involves the determination of a reporting unit’s
fair value, which is predicated based on our assumptions regarding the future
economic prospects of the reporting unit. Such assumptions include
(i) discrete financial forecasts for the assets contained within the reporting
unit, which rely on management’s estimates of operating margins and
transportation volumes; (ii) long-term growth rates for cash flows beyond the
discrete forecast period and (iii) appropriate discount rates. Based on
our most recent goodwill impairment testing, each reporting unit’s fair value
was substantially in excess (a minimum of 10%) of its carrying
value.
The
following table summarizes components of our goodwill amounts by segment at
December 31, 2009:
|
NGL
Pipelines & Services
|
||||
|
Acquisition
of ownership interests in TEPPCO
|
$ | 72.2 | ||
|
GulfTerra
Merger
|
23.8 | |||
|
Acquisition
of Encinal
|
95.3 | |||
|
Acquisition
of interest in Dixie
|
80.3 | |||
|
Acquisition
of Great Divide
|
44.9 | |||
|
Acquisition
of Indian Springs natural gas processing business
|
13.2 | |||
|
Other
|
11.5 | |||
|
Onshore
Natural Gas Pipelines & Services
|
||||
|
GulfTerra
Merger
|
279.9 | |||
|
Other
|
5.0 | |||
|
Onshore
Crude Oil Pipeline & Services
|
||||
|
Acquisition
of ownership interests in TEPPCO
|
288.8 | |||
|
Acquisition
of crude oil pipeline and services business
|
14.2 | |||
|
Offshore
Pipelines & Services
|
||||
|
GulfTerra
Merger
|
82.1 | |||
|
Petrochemical
& Refined Products Services
|
||||
|
Acquisition
of ownership interests in TEPPCO
|
842.3 | |||
|
Acquisition
of marine services businesses
|
90.4 | |||
|
Acquisition
of Mont Belvieu propylene fractionation business
|
73.7 | |||
|
Other
(1)
|
0.7 | |||
|
Total
|
$ | 2,018.3 | ||
|
(1)
Includes
a non-cash impairment charge of $1.3 million, see Note 5 for additional
information.
|
||||
Goodwill
attributable to the acquisition of ownership interests in
TEPPCO. As a result of our ownership of 100% of the
limited and general partner interests of TEPPCO following the recently completed
TEPPCO Merger, we applied push down accounting to the $1.2 billion of goodwill
recorded by affiliates of EPCO (which are under common control with us) when
they acquired 100% of the membership interests of TEPPCO GP and 4,400,000 TEPPCO
limited partner units from a third-party in February 2005.
The $1.2
billion in push down goodwill represents the excess of the purchase price paid
by such affiliates to acquire ownership interests in TEPPCO in February 2005
over the respective fair value of assets acquired and liabilities assumed in the
February 2005 transaction. Management attributes the $1.2 billion of
goodwill to the future economic benefits we may realize from our ownership of
TEPPCO, including anticipated commercial synergies and cost
savings.
TEPPCO
owns and operates an extensive network of assets that facilitate the movement,
marketing, gathering and storage services of various commodities and
energy-related products. TEPPCO’s pipeline network is comprised of
approximately 12,500 miles of pipelines that gather and transport refined
products, crude oil, natural gas and NGLs, including one of the largest common
carrier pipelines for refined products in the United States. TEPPCO
also owns a marine services business that transports refined products, crude
oil, asphalt, condensate, heavy fuel oil and other heated oil products via tow
boats and tank barges. In addition, TEPPCO owns interests in the
Seaway and Centennial pipeline systems.
Goodwill
attributable to GulfTerra Merger. Goodwill recorded in
connection with the GulfTerra Merger can be attributed to our belief (at the
time the merger was consummated) that the combined partnerships would benefit
from the strategic location of each partnership’s assets and the industry
relationships that each possessed. In addition, we expected that
various operating synergies could develop (such as reduced general and
administrative costs and interest savings) that would result in improved
financial results for the merged entity. Based on miles of pipelines,
GulfTerra was one of the largest natural gas gathering and transportation
companies in the United States, serving producers in the central and western
Gulf of Mexico and onshore in Texas and New Mexico. These regions
offer us significant growth potential through the acquisition and construction
of additional pipelines, platforms, processing and storage facilities and other
midstream energy infrastructure.
Acquisition
of Encinal. Management attributes goodwill recorded in
connection with the Encinal acquisition to potential future benefits we may
realize from our other south Texas processing and NGL businesses as a result of
acquiring the Encinal business. Specifically, our acquisition of the
long-term dedication rights associated with the Encinal business is expected to
add value to our south Texas processing facilities and related NGL businesses
due to increased volumes. The Encinal goodwill is recorded as part of
the NGL Pipelines & Services business segment due to management’s belief
that such future benefits will accrue to businesses classified within this
segment.
Acquisition
of Dixie and Great Divide. In 2008, we recorded goodwill in connection
with our acquisition of the remaining third-party interest in Dixie and with the
acquisition of Great Divide. The remaining ownership interests in
Dixie were acquired from Amoco Pipeline Holding Company in August
2008. Management attributes the goodwill to future earnings growth on
the Dixie Pipeline. Specifically, a 100% ownership interest in the
Dixie Pipeline will increase our flexibility to pursue future
opportunities. Great Divide was acquired from EnCana in December
2008. The Great Divide goodwill is attributable to management’s
expectations of future economics benefits derived from incremental natural gas
processing margins and other downstream activities.
The Dixie
and Great Divide goodwill amounts are recorded as part of the NGL Pipelines
& Services business segment due to management’s belief that such future
benefits will accrue to businesses classified within this segment.
Acquisition
of Cenac and Horizon. Also in 2008, we recorded goodwill in
connection with our acquisition of marine services businesses, which are
recorded as a part of the Petrochemical & Refined Products Services business
segment due to management’s belief of potential future economic benefits we
expect to realize as a result of acquiring these assets.
Other
goodwill amounts. The remainder of our goodwill amounts are
associated with prior acquisitions, principally that of our crude oil pipeline
and services business originally purchased by TEPPCO in 2001, our purchase of a
propylene fractionation business in February 2002 and our acquisition of
indirect ownership interests in the Indian Springs natural gas gathering and
processing business in January 2005.
Our
consolidated debt obligations consisted of the following at December 31,
2009:
|
EPO
senior debt obligations:
|
||||
|
Multi-Year
Revolving Credit Facility, variable-rate, due November
2012
|
$ | 195.5 | ||
|
Pascagoula
MBFC Loan, 8.70% fixed-rate, due March 2010 (1)
|
54.0 | |||
|
Petal
GO Zone Bonds, variable-rate, due August 2037
|
57.5 | |||
|
Senior
Notes B, 7.50% fixed-rate, due February 2011
|
450.0 | |||
|
Senior
Notes C, 6.375% fixed-rate, due February 2013
|
350.0 | |||
|
Senior
Notes D, 6.875% fixed-rate, due March 2033
|
500.0 | |||
|
Senior
Notes G, 5.60% fixed-rate, due October 2014
|
650.0 | |||
|
Senior
Notes H, 6.65% fixed-rate, due October 2034
|
350.0 | |||
|
Senior
Notes I, 5.00% fixed-rate, due March 2015
|
250.0 | |||
|
Senior
Notes J, 5.75% fixed-rate, due March 2035
|
250.0 | |||
|
Senior
Notes K, 4.95% fixed-rate, due June 2010 (1)
|
500.0 | |||
|
Senior
Notes L, 6.30% fixed-rate, due September 2017
|
800.0 | |||
|
Senior
Notes M, 5.65% fixed-rate, due April 2013
|
400.0 | |||
|
Senior
Notes N, 6.50% fixed-rate, due January 2019
|
700.0 | |||
|
Senior
Notes O, 9.75% fixed-rate, due January 2014
|
500.0 | |||
|
Senior
Notes P, 4.60% fixed-rate, due August 2012
|
500.0 | |||
|
Senior
Notes Q, 5.25% fixed-rate, due January 2020
|
500.0 | |||
|
Senior
Notes R, 6.125% fixed-rate, due October 2039
|
600.0 | |||
|
Senior
Notes S, 7.625% fixed-rate, due February 2012 (2)
|
490.5 | |||
|
Senior
Notes T, 6.125% fixed-rate, due February 2013 (2)
|
182.5 | |||
|
Senior
Notes U, 5.90% fixed-rate, due April 2013 (2)
|
237.6 | |||
|
Senior
Notes V, 6.65% fixed-rate, due April 2018 (2)
|
349.7 | |||
|
Senior
Notes W, 7.55% fixed-rate, due April 2038 (2)
|
399.6 | |||
|
TEPPCO
senior debt obligations:
|
||||
|
TEPPCO
Senior Notes (2)
|
40.1 | |||
|
Duncan
Energy Partners’ debt obligations:
|
||||
|
DEP
Revolving Credit Facility, variable-rate, due February
2011
|
175.0 | |||
|
DEP
Term Loan, variable-rate, due December 2011
|
282.3 | |||
|
Total
principal amount of senior debt obligations
|
9,764.3 | |||
|
EPO
Junior Subordinated Notes A, fixed/variable-rate, due August
2066
|
550.0 | |||
|
EPO
Junior Subordinated Notes B, fixed/variable-rate, due January
2068
|
682.7 | |||
|
EPO
Junior Subordinated Notes C, fixed/variable-rate, due June 2067
(2)
|
285.8 | |||
|
TEPPCO
Junior Subordinated Notes, fixed/variable-rate, due June 2067 (2)
|
14.2 | |||
|
Total
principal amount of senior and junior debt obligations
|
11,297.0 | |||
|
Other,
non-principal amounts:
|
||||
|
Change
in fair value of debt-related derivative instruments (see Note
5)
|
44.4 | |||
|
Unamortized
discounts, net of premiums
|
(18.7 | ) | ||
|
Unamortized
deferred net gains related to terminated interest rate swaps (see Note
5)
|
23.7 | |||
|
Total
other, non-principal amounts
|
49.4 | |||
|
Total
long-term debt
|
$ | 11,346.4 | ||
|
(1)
Long-term
and current maturities of debt reflect the classification of such
obligations at December 31, 2009 after taking into consideration
EPO’s ability to use available borrowing capacity under its Multi-Year
Revolving Credit Facility.
(2)
Substantially
all of TEPPCO debt obligations were exchanged for a corresponding series
of new EPO notes in October 2009 in connection with the TEPPCO
Merger.
|
||||
Letters
of Credit
At
December 31, 2009, EPO had outstanding a $50.0 million letter of credit related
to its commodity derivative instruments and a $58.3 million letter of credit
related to its Petal GO Zone Bonds. These letter of credit facilities
do not reduce the amount available for borrowing under EPO’s credit
facilities.
Parent-Subsidiary
Guarantor Relationships
Enterprise
Products Partners acts as guarantor of the consolidated debt obligations of EPO
with the exception of the DEP Revolving Credit Facility and the DEP Term Loan
Agreement. If EPO were to default on any of its guaranteed debt,
Enterprise Products Partners L.P. would be responsible for full repayment of
that obligation. Additionally, TEPPCO’s remaining debt obligations
are non-recourse to Enterprise Products Partners.
EPO’s
Debt Obligations
Multi-Year
Revolving Credit Facility. We have in place a $1.75 billion
unsecured revolving credit facility, including the issuance of letters of credit
(“Multi-Year Revolving Credit Facility”), which matures in November
2012. Our credit facility has a term-out option that allows for us on
the maturity date to convert the principal balance of all revolving loans then
outstanding into a non-revolving one-year term loan. The credit facility
allows us to request unlimited one-year extensions of the maturity date, subject
to lender approval. The total amount of the
bank commitments may be increased, without the consent of the lenders, by an
amount not exceeding $500.0 million by adding one or more lenders to the
facility and/or requesting that the commitments of existing lenders be
increased.
As
defined by the credit agreement, variable interest rates charged under this
facility bear interest at a Eurodollar rate plus an applicable
margin. In addition, EPO is required to pay a quarterly facility fee
on each lender’s commitment irrespective of commitment usage. The
applicable margins will be increased by 0.1% per annum for each day that the
total outstanding loans and letter of credit obligations under the facility
exceeds 50% of the total lender commitments. Also, if we exercise our
term-out option at the maturity date, the applicable margin will increase by
0.125% per annum and, if immediately prior to such election, the total amount of
outstanding loans and letter of credit obligations under the facility exceeds
50% of the total lender commitments, the applicable margin with respect to the
term loan will increase by an additional 0.1% per annum.
The
Multi-Year Revolving Credit Facility contains certain financial and other
customary affirmative and negative covenants. The credit agreement
also restricts EPO’s ability to pay cash distributions to us if a default or an
event of default (as defined in the credit agreement) has occurred and is
continuing at the time such distribution is scheduled to be paid.
EPO’s
borrowings under this agreement are unsecured general obligations that are
non-recourse to EPGP. We have guaranteed repayment of amounts due
under this revolving credit agreement through an unsecured
guarantee.
Pascagoula
MBFC Loan. This loan, from the Mississippi Business Finance
Corporation (“MBFC”), matured on March 1, 2010 and was repaid.
Petal GO
Zone Bonds. In August 2007,
Petal Gas Storage, L.L.C. (“Petal”), a wholly owned subsidiary of EPO,
borrowed $57.5 million from the MBFC pursuant to a loan agreement and
promissory note between Petal and the MBFC. The promissory note
between Petal and MBFC is guaranteed by EPO and supported by a letter of credit
issued by a bank that expires in August 2014. On the same date, the
MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds
to various third parties. The promissory note and the GO Zone
bonds have identical terms including floating interest rates and maturities of
30 years.
Petal
MBFC Loan. In August 2007,
Petal entered into a loan agreement and a promissory note with the MBFC under
which Petal may borrow up to $29.5 million. On the same date, the MBFC
issued taxable bonds to EPO in the maximum amount of $29.5 million. At
December 31, 2009, there was $8.9 million outstanding under the loan and the
bonds. The promissory note and the taxable bonds have
identical terms. The loan and bonds are netted in preparing our
Consolidated Balance Sheet.
Japanese
Yen Term Loan. In November
2008, EPO executed the Yen Term Loan in the amount of approximately 20.7 billion
yen (approximately $217.6 million U.S. Dollar equivalent on the closing
date). EPO entered into foreign exchange currency swaps that
effectively converted the loan into a U.S. Dollar loan with a fixed interest
rate of approximately 4.93%. The Yen Term Loan matured on March 30,
2009. Additionally, EPO executed a forward purchase exchange (yen
principal and interest due) at an exchange rate of 94.515 to eliminate foreign
exchange risk, resulting in a payment of US$221.6 million on March 30,
2009.
364-Day
Revolving Credit Facility.
From November 2008 through June 2009, we had a $375.0 million standby credit
facility. The facility was never utilized and was terminated in June
2009 under its terms as a result of issuing senior notes.
Senior
Notes. EPO’s senior fixed-rate notes are unsecured obligations
and rank equally with its existing and future unsecured and unsubordinated
indebtedness. They are senior to any future subordinated
indebtedness. EPO’s borrowings under these notes are non-recourse to
EPGP. Enterprise Products Partners has guaranteed repayment of
amounts due under these notes through an unsecured and unsubordinated
guarantee. Enterprise Products Partners guarantee of such notes is
non-recourse to EPGP. Our senior notes are subject to make-whole
redemption rights and were issued under indentures containing certain covenants,
which generally restrict EPO’s ability, with certain exceptions, to incur debt
secured by liens and engage in sale and leaseback transactions.
In June
2009, EPO issued $500.0 million in principal amount of 3-year senior unsecured
notes (Senior Notes P) at 99.95% of their principal amount. In
October 2009, EPO issued: (i) $500.0 million in principal amount of 10-year
unsecured notes (Senior Notes Q) at 99.355% of their principal amount and (ii)
$600.0 million in principal amount of 30-year unsecured notes (Senior Notes R)
at 99.386% of their principal amount. Net proceeds from the issuance
of these senior notes were used (i) to repay amounts borrowed under a $200.0
million term loan that EPO entered into during April 2009, (ii) to repay $500.0
million in aggregate principal amount of Senior Notes F that matured in October
2009, (iii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year
Revolving Credit Facility and (iv) for general partnership
purposes.
In
connection with the TEPPCO Merger, EPO offered to exchange all of TEPPCO’s
outstanding senior notes for a corresponding series of new EPO senior
notes. The exchanges were completed on October 27, 2009 as
follows:
|
TEPPCO
Notes
Exchanged
|
Corresponding
Series
of New
EPO
Notes
|
Aggregate
Principal
Amount
|
Principal
Amount
Exchanged
|
Principal
Amount
Remaining
|
|||||||||
|
TEPPCO
Senior Notes, 7.625%
fixed-rate,
due February 2012
|
Senior
Notes S, 7.625%
fixed-rate,
due February 2012
|
$ | 500.0 | $ | 490.5 | $ | 9.5 | ||||||
|
TEPPCO
Senior Notes, 6.125%
fixed-rate,
due February 2013
|
Senior
Notes T, 6.125%
fixed-rate,
due February 2013
|
200.0 | 182.5 | 17.5 | |||||||||
|
TEPPCO
Senior Notes, 5.90%
fixed-rate,
due April 2013
|
Senior
Notes U, 5.90%
fixed-rate,
due April 2013
|
250.0 | 237.6 | 12.4 | |||||||||
|
TEPPCO
Senior Notes, 6.65%
fixed-rate,
due April 2018
|
Senior
Notes V, 6.65%
fixed-rate,
due April 2018
|
350.0 | 349.7 | 0.3 | |||||||||
|
TEPPCO
Senior Notes, 7.55%
fixed-rate,
due April 2038
|
Senior
Notes W, 7.55%
fixed-rate,
due April 2038
|
400.0 | 399.6 | 0.4 | |||||||||
| $ | 1,700.0 | $ | 1,659.9 | $ | 40.1 | ||||||||
Junior
Subordinated Notes. EPO’s payment obligations under its junior
notes are subordinated to all of its current and future senior indebtedness (as
defined in the related indenture agreement). Enterprise Products
Partners has guaranteed repayment of amounts due under these notes through an
unsecured and subordinated guarantee. The indenture agreement
governing these notes allows EPO to defer interest payments on one or more
occasions for up to ten consecutive years subject to certain
conditions. During any period in which interest payments are deferred
and subject to certain exceptions, neither we nor EPO can declare or make any
distributions to any of our respective equity securities or make any payments on
indebtedness or other obligations that rank pari passu with or are subordinate
to our junior notes. Each
series of
our subordinated junior notes are ranked equally with each
other. Generally, each series of junior subordinated notes are not
redeemable by EPO without payment of a make-whole premium while the notes bear
interest at a fixed annual rate.
In
connection with the issuance of each series of junior subordinated notes, EPO
entered into separate Replacement Capital Covenants in favor of covered debt
holders (as defined in the underlying documents) pursuant to which EPO agreed
for the benefit of such debt holders that it would not redeem or repurchase such
junior notes unless such redemption or repurchase is made using proceeds from
the issuance of certain securities.
In
connection with the TEPPCO Merger, EPO offered to exchange TEPPCO’s outstanding
junior subordinated notes for a corresponding series of new EPO junior
subordinated notes. The exchange was completed on October 27,
2009:
|
TEPPCO
Notes
Exchanged
|
Corresponding
Series
of New
EPO
Notes
|
Aggregate
Principal
Amount
|
Principal
Amount
Exchanged
|
Principal
Amount
Remaining
|
|
TEPPCO
Junior Subordinated Notes,
fixed/variable-rate,
due
June 2067
|
EPO
Junior Subordinated Notes C,
fixed/variable-rate,
due June 2067
|
$ 300.0
|
$ 285.8
|
$ 14.2
|
The
following table summarizes the interest rate terms of our junior subordinated
notes:
|
Variable
Annual
|
||
|
Fixed
Annual
|
Interest
Rate
|
|
|
Series
|
Interest
Rate
|
Thereafter
|
|
Junior
Subordinated Notes A
|
8.375%
through August 2016 (1)
|
3-month
LIBOR rate + 3.708% (4)
|
|
Junior
Subordinated Notes B
|
7.034% through
January 2018 (2)
|
Greater
of: (i) 3-month LIBOR rate + 2.68% or (ii)
7.034% (5)
|
|
Junior
Subordinated Notes C
|
7.00% through
June 2017 (3)
|
3-month
LIBOR rate + 2.778% (6)
|
|
(1)
Interest
is payable semi-annually in arrears in February and August of each year,
which commenced in February 2007.
(2)
Interest
is payable semi-annually in arrears in January and July of each year,
which commenced in January 2008.
(3)
Interest
is payable semi-annually in arrears in June and December of each year,
which commenced in December 2009.
(4)
Interest
is payable quarterly in arrears in February, May, August and November of
each year commencing in November 2016.
(5)
Interest
is payable quarterly in arrears in January, April, July and October of
each year commencing in April 2018.
(6)
Interest
is payable quarterly in arrears in March, June, September and December of
each year commencing in June 2017.
|
||
TEPPCO’s
Debt Obligations
TEPPCO
Revolving Credit Facility. Upon consummation of the TEPPCO
Merger, EPO repaid and terminated all of the outstanding indebtedness under the
TEPPCO Revolving Credit Facility.
TEPPCO
Senior Notes.
As
previously discussed, on October 27, 2009, $1.66 billion of the TEPPCO Senior
Notes were exchanged for an equal amount of new EPO Senior Notes. In addition to the debt
exchange, substantially all of the restrictive covenants and reporting
requirements associated with the remaining TEPPCO Senior Notes were eliminated
through amendments that became effective on October 27, 2009.
TE
Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and
Val Verde Gas Gathering Company, L.P. (collectively, the “Subsidiary
Guarantors”) acted as guarantors of TEPPCO’s outstanding senior notes through
November 2009. The subsidiary guarantees were terminated in November
2009.
TEPPCO
Junior Subordinated Notes. As discussed above, on October 27,
2009, $285.8 million of the TEPPCO Junior Subordinated Notes were exchanged for
an equal amount of new EPO Junior Subordinated Notes. In addition to
the debt exchange, substantially all of the restrictive covenants and reporting
requirements associated with the remaining TEPPCO Junior Subordinated Notes were
eliminated through amendments that became effective on October 27,
2009.
The
Subsidiary Guarantors also acted as guarantors, on a junior subordinated basis,
of TEPPCO’s outstanding junior subordinated notes through November
2009. These subsidiary guarantees were terminated in November
2009.
The terms
and provisions of the TEPPCO’s Junior Subordinated Notes are similar to each
series of EPO’s junior subordinated notes. For example, they: (i) are
general unsecured subordinated obligations, (ii) allow interest payments to be
deferred for multiple periods of up to ten consecutive years and (iii) are
subordinated in right of payment to all existing and future senior
indebtedness. The maturity date, the interest rate and the interest
payment due dates are the identical to EPO’s Junior Subordinated Notes C as
discussed above.
In
connection with the issuance of the TEPPCO Junior Subordinated Notes, TEPPCO and
its Subsidiary Guarantors entered into a Replacement Capital Covenant in favor
of the covered debt holders (as defined in the underlying documents) pursuant to
which TEPPCO agreed for the benefit of such debt holders that it would not
redeem or repurchase such junior notes unless such redemption or repurchase is
made using proceeds from the issuance of certain securities. The
Replacement Capital Covenant is not a term of the governing indenture or the
junior subordinated notes.
Duncan
Energy Partners’ Debt Obligations
We
consolidate the debt of Duncan Energy Partners with that of our own; however, we
do not have the obligation to make interest payments or debt payments with
respect to the debt of Duncan Energy Partners.
DEP
Revolving Credit Facility. Duncan Energy
Partners has in place a $300.0 million unsecured revolving credit facility, all
of which may be used for letters of credit, with a $30.0 million sublimit for
Swingline loans. This credit facility will be used by Duncan Energy
Partners in the future to fund working capital and other capital requirements
and for general partnership purposes. Duncan Energy Partners may make
up to two requests for one-year extensions of the maturity date, which is
February 2011 (subject to certain restrictions). The revolving credit
facility is available to pay distributions to its partners, fund working
capital, make acquisitions and provide payment for general
purposes. Duncan Energy Partners can increase the 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.
This revolving credit facility offers
the following unsecured loans, each having different interest requirements: (i)
a Eurodollar rate, plus the applicable Eurodollar margin (as defined in the
credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal
to the higher of (a) the rate of interest publicly announced by the
administrative agent, Wachovia Bank, National Association, as its Base Rate and
(b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii)
Swingline loans bear interest at a rate per annum equal to LIBOR plus an
applicable LIBOR margin.
The Duncan Energy Partners’ 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.
DEP Term
Loan. In April 2008,
Duncan Energy Partners entered into a standby term loan agreement consisting of
commitments for up to a $300.0 million senior unsecured term
loan. Subsequently, commitments under this agreement decreased to
$282.3 million due to bankruptcy of one of the lenders. Duncan Energy
Partners borrowed the full amount of $282.3 million on December 8, 2008 in
connection with the acquisition of equity interests in midstream energy
businesses.
Duncan Energy Partners 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.
Dixie
Revolving Credit Facility
Dixie’s
debt obligation consisted of a senior, unsecured revolving credit facility
having a borrowing capacity of $28.0 million. This credit facility
was terminated in January 2009.
Canadian
Debt Obligation
In May
2007, Canadian Enterprise Gas Products, Ltd., a wholly owned subsidiary of EPO,
entered into a $30.0 million Canadian revolving credit facility with The Bank of
Nova Scotia. The credit facility, which includes the issuance of
letters of credit, matures in October 2011. Letters of credit
outstanding under this facility reduce the amount available for
borrowings. The credit facility contains customary covenants and
events of default. The obligations under the credit facility are
guaranteed by EPO. As of December 31, 2009, there were no debt
obligations outstanding under this credit facility.
Covenants
We were
in compliance with the financial covenants of our consolidated debt agreements
at December 31, 2009.
Information
Regarding Variable Interest Rates Paid
The
following table presents the range of interest rates and weighted-average
interest rates paid on our consolidated variable-rate debt obligations during
the year ended December 31, 2009:
|
Range
of
|
Weighted-Average
|
|
|
Interest
Rates
|
Interest
Rate
|
|
|
Paid
|
Paid
|
|
|
EPO
Multi-Year Revolving Credit Facility
|
0.73%
to 3.25%
|
0.95%
|
|
TEPPCO
Revolving Credit Facility
|
0.75%
to 3.25%
|
0.88%
|
|
DEP
Revolving Credit Facility
|
0.81%
to 2.74%
|
1.48%
|
|
DEP
Term Loan
|
0.93%
to 2.93%
|
1.15%
|
|
Petal
GO Zone Bonds
|
0.21%
to 2.75%
|
0.60%
|
Consolidated
Debt Maturity Table
The
following table presents contractually scheduled maturities of our consolidated
debt obligations for the next five years, and in total
thereafter.
|
Scheduled
Maturities of Debt
|
||||||||||||||||||||||||||||
|
After
|
||||||||||||||||||||||||||||
|
Total
|
2010 (1)
|
2011
|
2012
|
2013
|
2014
|
2014
|
||||||||||||||||||||||
|
Revolving
Credit Facilities
|
$ | 370.5 | $ | -- | $ | 175.0 | $ | 195.5 | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
Senior
Notes
|
9,000.0 | 500.0 | 450.0 | 1,000.0 | 1,200.0 | 1,150.0 | 4,700.0 | |||||||||||||||||||||
|
Term
Loans
|
282.3 | -- | 282.3 | -- | -- | -- | -- | |||||||||||||||||||||
|
Junior
Subordinated Notes
|
1,532.7 | -- | -- | -- | -- | -- | 1,532.7 | |||||||||||||||||||||
|
Other
|
111.5 | 54.0 | -- | -- | -- | -- | 57.5 | |||||||||||||||||||||
|
Total
|
$ | 11,297.0 | $ | 554.0 | $ | 907.3 | $ | 1,195.5 | $ | 1,200.0 | $ | 1,150.0 | $ | 6,290.2 | ||||||||||||||
|
(1) Long-term
and current maturities of debt reflect the classification of such
obligations on our Consolidated Balance Sheet at December 31, 2009 after
taking into consideration EPO’s ability to use available borrowing
capacity under its Multi-Year Revolving Credit Facility.
|
||||||||||||||||||||||||||||
Debt
Obligations of Unconsolidated Affiliates
We have
three unconsolidated affiliates with long-term debt obligations. The
following table shows (i) the ownership interest in each entity at December 31,
2009, (ii) total debt of each unconsolidated affiliate at December 31, 2009 (on
a 100% basis to the unconsolidated affiliate) and (iii) the corresponding
scheduled maturities of such debt.
|
Scheduled
Maturities of Debt
|
||||||||||||||||||||||||||||||||
|
Ownership
|
After
|
|||||||||||||||||||||||||||||||
|
Interest
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
2014
|
|||||||||||||||||||||||||
|
Poseidon
|
36% | $ | 92.0 | $ | -- | $ | 92.0 | $ | -- | $ | -- | $ | -- | $ | -- | |||||||||||||||||
|
Evangeline
|
49.5% | 10.7 | 3.2 | 7.5 | -- | -- | -- | -- | ||||||||||||||||||||||||
|
Centennial
|
50% | 120.0 | 9.1 | 9.0 | 8.9 | 8.6 | 8.6 | 75.8 | ||||||||||||||||||||||||
|
Total
|
$ | 222.7 | $ | 12.3 | $ | 108.5 | $ | 8.9 | $ | 8.6 | $ | 8.6 | $ | 75.8 | ||||||||||||||||||
The
credit agreements of these unconsolidated affiliates include customary
covenants, including financial covenants. These businesses were in
compliance with such financial covenants at December 31, 2009. The
credit agreements of these unconsolidated affiliates restrict their ability to
pay cash dividends or distributions if a default or an event of default (as
defined in each credit agreement) has occurred and is continuing at the time
such dividend or distribution is scheduled to be paid.
The
following information summarizes the significant terms of the debt obligations
of these unconsolidated affiliates at December 31, 2009:
Poseidon. At
December 31, 2009, Poseidon’s debt obligations consisted of $92.0 million
outstanding under its $150.0 million variable-rate revolving credit
facility. Amounts borrowed under this facility mature in May 2011 and
are secured by substantially all of Poseidon’s assets. The
weighted-average variable interest rate charged on this debt at December 31,
2009 was 1.88%.
Evangeline. 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. The Series B senior secured notes are collateralized by
Evangeline’s property, plant and equipment; proceeds from a gas sales contract
and by a debt service reserve requirement.
Evangeline
incurred the subordinated note payable as a result of its acquisition of a
contract-based intangible asset in the early 1990s. This note is
subject to a subordination agreement which prevents the repayment of principal
and accrued interest on the subordinated note until such time as the Series B
noteholders 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 rate charged on this note at December 31, 2009 was
1.59%. Accrued interest payable related to the subordinated note was
$10.2 million at December 31, 2009.
Centennial. At
December 31, 2009, Centennial’s debt obligations consisted of $120.0 million
borrowed under a master shelf loan agreement through two private placements,
with interest rates ranging from 7.99% to 8.09%. Borrowings under the
master shelf agreement mature in May 2024 and are collateralized by
substantially all of Centennial’s assets and severally guaranteed by
Centennial’s owners.
We and
our joint venture partner in Centennial have each guaranteed one-half of
Centennial’s debt obligations. If Centennial were to default on its
debt obligations, the estimated payment obligation would be $60.0 million based
on amounts outstanding at December 31, 2009. We recognized a
liability of $8.4 million for our share of the Centennial debt guaranty at
December 31, 2009.
At
December 31, 2009, equity consisted of our member’s capital account,
consolidated accumulated other comprehensive loss amounts, and noncontrolling
interest.
Accumulated
Other Comprehensive Loss
The
following table summarizes transactions affecting our AOCI during the year ended
December 31, 2009.
|
Balance,
December 31, 2008
|
$ | (2.0 | ) | |
|
Net
commodity derivative gains during period
|
2.3 | |||
|
Net
interest rate derivative gains during period
|
0.3 | |||
|
Transfer
of AOCI balance to noncontrolling interest
|
(0.8 | ) | ||
|
Balance,
December 31, 2009
|
$ | (0.2 | ) |
Noncontrolling
Interest
The
following table shows the components of noncontrolling interest at December 31,
2009:
|
Limited
partners of Enterprise Products Partners:
|
||||
|
Third-party
owners of Enterprise Products Partners (1)
|
$ | 7,002.4 | ||
|
Related
party owners of Enterprise Products Partners (2)
|
1,924.2 | |||
|
Limited
partners of Duncan Energy Partners:
|
||||
|
Third-party
owners of Duncan Energy Partners (3)
|
414.3 | |||
|
Related
party owners of Duncan Energy Partners
|
1.7 | |||
|
Joint
venture partners (4)
|
117.5 | |||
|
Accumulated
other comprehensive loss attributable to
|
||||
|
noncontrolling
interest
|
(11.5 | ) | ||
|
Total
noncontrolling interest on Consolidated Balance Sheet
|
$ | 9,448.6 | ||
|
(1)
Consists
of non-affiliate public unitholders of Enterprise Products
Partners.
(2)
Consists
of unitholders of Enterprise Products Partners that are related party
affiliates. This group is primarily comprised of EPCO and certain of
its private company consolidated subsidiaries.
(3)
Consists
of non-affiliate public unitholders of Duncan Energy
Partners.
(4)
Represents
third-party ownership interests in joint ventures that we consolidate,
including Rio Grande Pipeline, LLC, Seminole Pipeline Company, Tri-States
Pipeline, L.L.C., Independence Hub, LLC and Wilprise Pipeline Company,
L.L.C.
|
||||
We have
five reportable business segments: NGL Pipelines & Services, Onshore Natural
Gas Pipelines & Services, Onshore Crude Oil Pipelines & Services,
Offshore Pipelines & Services and Petrochemical & Refined Products
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.
Our
integrated midstream energy asset system (including the midstream energy assets
of our equity method investees) provides services to producers and consumers of
natural gas, NGLs, crude oil, refined products and certain
petrochemicals. In general, hydrocarbons enter our asset system in a
number of ways, such as an offshore natural gas or crude oil pipeline, an
offshore platform, a natural gas processing plant, an onshore natural gas
gathering pipeline, an NGL fractionator, an NGL storage facility or an NGL
transportation or distribution pipeline.
Many of
our equity investees are included within our integrated midstream asset
system. For example, we have ownership interests in several offshore
natural gas, refined products and crude oil pipelines. Other examples
include our use of the Promix NGL fractionator to process mixed
NGLs
extracted
by our gas plants. The fractionated NGLs we receive from Promix can
then be sold in our NGL marketing activities. Additionally, our use
of the Centennial pipeline, which loops the refined products pipeline system
between Beaumont, Texas and southern Illinois, permits effective supply of
product to points south of Illinois as well as incremental product supply
capacity to mid-continent markets downstream of southern Illinois.
The
majority of our plant-based operations are located in Texas, Louisiana,
Mississippi, New Mexico, Colorado and Wyoming. Our natural gas, NGL,
refined products and crude oil pipelines are located in a number of regions of
the United States including (i) the Gulf of Mexico offshore Texas, Louisiana,
and onshore in Colorado; (ii) the south and southeastern United States
(primarily in Texas, Louisiana, Mississippi and Alabama); (iii) the Midwestern
and northeastern United States and (iv) certain regions of the central and
western United States, including the Rocky Mountains. Our marketing
activities are headquartered in Houston, Texas and Oklahoma City, Oklahoma and
serve customers in a number of regions of the United States including the Gulf
Coast, West Coast and Mid-Continent areas.
Segment
assets consist of property, plant and equipment, investments in unconsolidated
affiliates, 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 (a non-GAAP
performance measure) 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.
We consolidate the balance sheet of
Enterprise Products Partners with that of our own.
Information
by segment, together with reconciliations to our consolidated totals, is
presented in the following table at December 31, 2009:
|
Reportable
Segments
|
||||||||||||||||||||||||||||
|
Onshore
|
Onshore
|
Petrochemical
|
||||||||||||||||||||||||||
|
NGL
|
Natural
Gas
|
Crude
Oil
|
Offshore
|
&
Refined
|
Adjustments
|
|||||||||||||||||||||||
|
Pipelines
|
Pipelines
|
Pipelines
|
Pipelines
|
Products
|
and
|
Consolidated
|
||||||||||||||||||||||
|
&
Services
|
&
Services
|
&
Services
|
&
Services
|
Services
|
Eliminations
|
Totals
|
||||||||||||||||||||||
|
Segment
assets:
|
$ | 7,191.2 | $ | 6,918.7 | $ | 865.3 | $ | 2,121.4 | $ | 3,359.0 | $ | 1,207.3 | $ | 21,662.9 | ||||||||||||||
|
Property,
plant and equipment, net
(see
Note 7):
|
6,392.8 | 6,074.6 | 377.3 | 1,480.9 | 2,156.3 | 1,207.3 | 17,689.2 | |||||||||||||||||||||
|
Investments
in unconsolidated affiliates
(see
Note 8):
|
141.6 | 32.0 | 178.5 | 456.9 | 81.6 | -- | 890.6 | |||||||||||||||||||||
|
Intangible
assets, net (see Note 10):
|
315.6 | 527.2 | 6.5 | 101.5 | 114.0 | -- | 1,064.8 | |||||||||||||||||||||
|
Goodwill
(see Note 10):
|
341.2 | 284.9 | 303.0 | 82.1 | 1,007.1 | -- | 2,018.3 | |||||||||||||||||||||
The
following table summarizes our related party receivable and payable amounts at
December 31, 2009:
|
Accounts
receivable - related parties:
|
||||
|
EPCO
and affiliates
|
$ | -- | ||
|
Energy
Transfer Equity and subsidiaries
|
28.2 | |||
|
Other
|
10.2 | |||
|
Total
accounts receivable – related parties
|
$ | 38.4 | ||
|
Accounts
payable - related parties:
|
||||
|
EPCO
and affiliates
|
$ | 26.8 | ||
|
Energy
Transfer Equity and subsidiaries
|
33.4 | |||
|
Other
|
9.6 | |||
|
Total
accounts payable – related parties
|
$ | 69.8 | ||
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.
Relationship
with EPCO and Affiliates
We have
an extensive and ongoing relationship with EPCO and its affiliates, which
include the following significant entities that are not a part of our
consolidated group of companies:
|
§
|
EPCO
and its privately held affiliates;
|
|
§
|
Enterprise
GP Holdings, which owns and controls our general partner;
and
|
|
§
|
the
Employee Partnerships (see Note 4).
|
EPCO is a
privately held company controlled by Dan L. Duncan, who is also a Director and
Chairman of EPGP. At December 31, 2009, EPCO and its affiliates
beneficially owned interests in the following entities:
|
Percentage
of
|
||
|
Number
of Units
|
Outstanding
Units
|
|
|
Enterprise
Products Partners (1) (2)
|
191,363,613
|
31.3%
|
|
Enterprise
GP Holdings (3)
|
108,503,133
|
78.0%
|
|
(1)
Includes
4,520,431 Class B units and 21,167,783 common units owned by Enterprise GP
Holdings.
(2)
Enterprise
GP Holdings owns 100% of EPGP.
(3)
An
affiliate of EPCO also owns 100% of the general partner of Enterprise GP
Holdings, EPE Holdings.
|
||
The
principal business activity of EPGP is to act as the sole managing partner of
Enterprise Products Partners. The executive officers and certain of
the directors of EPGP and EPE Holdings are employees of EPCO. The
following table presents cash distributions received by EPGP for the year ended
December 31, 2009:
|
General
partner distributions
|
$ | 21.8 | ||
|
Incentive
distributions
|
161.3 | |||
|
Total
distributions
|
$ | 183.1 |
We and
Enterprise Products Partners are both separate legal entities apart from each
other and apart from EPCO, Enterprise GP Holdings and their respective other
affiliates, with assets and liabilities that are separate from those of EPCO,
Enterprise GP Holdings and their respective other affiliates. EPCO
and its privately held subsidiaries depend on the cash distributions they
receive from Enterprise Products Partners, Enterprise GP Holdings and other
investments to fund their other operations and to meet their
debt
obligations. The following table presents cash distributions received
by EPCO and its privately held affiliates from Enterprise products Partners and
Enterprise GP Holdings for the year ended December 31, 2009:
|
Enterprise
Products Partners
|
$ | 314.5 | ||
|
Enterprise
GP Holdings
|
205.2 | |||
|
Total
distributions
|
$ | 519.7 |
Substantially all of the ownership
interests in Enterprise Products Partners that are owned or controlled by
Enterprise GP Holdings are pledged as security under its credit
facility. In addition, substantially all of the ownership interests
in Enterprise Products Partners that are owned or controlled by EPCO and its
affiliates, other than those interests owned by Enterprise GP Holdings, Dan
Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as
security under the credit facility of a privately held affiliate of
EPCO. This credit facility contains customary and other events of
default relating to EPCO and certain affiliates, including Enterprise GP
Holdings and Enterprise Products Partners.
We have entered into an agreement with
an affiliate of EPCO to provide trucking services to us for the transportation
of NGLs and other products. We also lease office space in various
buildings from affiliates of EPCO. The rental rates in these lease
agreements approximate market rates.
EPCO
ASA
We have
no employees. All of our operating functions and general and
administrative support services are provided by employees of EPCO pursuant to
the ASA or by other service providers. We, Duncan Energy 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 a named insured in its overall insurance
program, with the associated premiums and other costs being allocated to
us.
|
Under the ASA, EPCO subleases to us
(for $1 per year) certain equipment which it holds pursuant to operating leases
and has assigned to Enterprise Products Partners its purchase option under such
leases (the “retained leases”). EPCO remains liable for the actual
cash lease payments associated with these agreements. Enterprise
Products Partners records the full value of these payments made by EPCO on our
behalf as a non-cash related party operating lease expense, with the offset to
equity accounted for as a general contribution to our partnership.
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 with respect to
business opportunities (as defined within the ASA) with third
parties. 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 Enterprise Products Partners and
Enterprise GP Holdings to EPCO of distributions of cash or securities, if
any, made
by EPCO
Unit to its 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 Energy Transfer Equity
Enterprise
GP Holdings acquired equity method investments in Energy Transfer Equity and its
general partner in May 2007. As a result, Energy Transfer Equity and
its consolidated subsidiaries became related parties to our consolidated
businesses.
We have a
long-term revenue generating contract with Titan Energy Partners, L.P.
(“Titan”), a consolidated subsidiary of ETP. Titan purchases
substantially all of its propane requirements from us. The contract
continues until March 31, 2010 and contains renewal and extension
options. We and Energy Transfer Company (“ETC OLP”) transport natural
gas on each other’s systems and share operating expenses on certain
pipelines. ETC OLP also sells natural gas to us.
Relationships
with Unconsolidated Affiliates
Many of
our unconsolidated affiliates perform supporting or complementary roles to our
other business operations. Since we and our affiliates hold ownership
interests in these entities and directly or indirectly benefit from our related
party transactions with such entities, they are presented here. The
following information summarizes significant related party transactions with our
current unconsolidated affiliates:
|
§
|
We
sell natural gas to Evangeline, which, in turn, uses the natural gas to
satisfy supply commitments it has with a major Louisiana
utility.
|
|
§
|
We
pay Promix for the transportation, storage and fractionation of
NGLs. In addition, we sell natural gas to Promix for its plant
fuel requirements.
|
|
§
|
We
lease from Centennial pipeline capacity and pay for pipeline
transportation services.
|
|
§
|
We
pay Seaway for transportation and tank rentals in connection with our
crude oil marketing activities.
|
|
§
|
We
perform management services for certain of our unconsolidated
affiliates.
|
Relationship
with Duncan Energy Partners
Duncan
Energy Partners was formed in September 2006 and did not acquire any assets
prior to February 5, 2007, which was the date it completed its initial public
offering and acquired controlling interests in five midstream energy businesses
from EPO in a drop down transaction. On December 8, 2008, through a
second drop down transaction, Duncan Energy Partners acquired controlling
interests in three additional midstream energy 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 (i) the gathering,
transportation and storage of natural gas; (ii) NGL transportation and
fractionation; (iii) the storage of NGL and petrochemical products; (iv) the
transportation of petrochemical products and (v) the marketing of NGLs and
natural gas.
At
December 31, 2009, Duncan Energy Partners is owned 99.3% by its limited partners
and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of
EPO. DEP GP is responsible for managing the business and operations
of Duncan Energy Partners. DEP Operating Partnership L.P., a wholly
owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan
Energy Partners’ business. At December 31, 2009, EPO owned 58.6% of
Duncan Energy Partners’ limited partner interests and 100% of its general
partner. Due to our control of Duncan Energy Partners, its balance
sheet
is
consolidated with those of our own and our transactions with Duncan Energy
Partners are eliminated in consolidation.
Relationship
with Cenac
In
connection with our marine services acquisition in February 2008, Cenac and
affiliates became a related party of ours. We entered into a
transitional operating agreement with Cenac in which our fleet of tow boats and
tank barges (which were primarily acquired from Cenac) continued to be operated
by employees of Cenac for a period of up to two years following the
acquisition. Under this agreement, we paid Cenac a monthly operating
fee and reimbursed Cenac for personnel salaries and related employee benefit
expenses, certain repairs and maintenance expenses and insurance premiums on the
equipment. Effective August 1, 2009, the transitional operating
agreement was terminated. Personnel providing services pursuant to
the agreement became employees of EPCO and will continue to provide services
under the ASA. Concurrently with the termination of the transitional
operating agreement, we entered into a two-year consulting agreement with Mr.
Cenac and Cenac Marine Services, L.L.C. under which Mr. Cenac has agreed to
supervise the day-to-day operations of our marine services business and, at our
request, provide related management and transitional services.
Significant
components of deferred tax assets and deferred tax liabilities as of December
31, 2009 were as follows:
|
Deferred
tax assets:
|
||||
|
Net
operating loss carryovers (1)
|
$ | 24.6 | ||
|
Employee
benefit plans
|
2.8 | |||
|
Deferred
revenue
|
1.1 | |||
|
Equity
investment in partnerships
|
1.0 | |||
|
AROs
|
0.1 | |||
|
Accruals
|
1.3 | |||
|
Total
deferred tax assets
|
30.9 | |||
|
Valuation
allowance (2)
|
2.2 | |||
|
Net
deferred tax assets
|
28.7 | |||
|
Deferred
tax liabilities:
|
||||
|
Property,
plant and equipment
|
97.4 | |||
|
Total
deferred tax liabilities
|
97.4 | |||
|
Total
net deferred tax liabilities
|
$ | (68.7 | ) | |
|
Current
portion of total net deferred tax assets
|
$ | 1.9 | ||
|
Long-term
portion of total net deferred tax liabilities
|
$ | (70.6 | ) | |
|
(1)
These
losses expire in various years between 2010 and 2028 and are subject to
limitations on their utilization.
(2)
We
record a valuation allowance to reduce our deferred tax assets to the
amount of future benefit that is more likely than not to be
realized.
|
||||
On May
18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing
state franchise tax. In general, legal entities that conduct business
in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin
Tax), including previously non-taxable entities such as limited
liability companies, limited partnerships and limited liability
partnerships. The tax is assessed on Texas sourced taxable margin
which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue
less (a) cost of goods sold or (b) compensation and benefits.
Although
the bill states that the Texas Margin Tax is not an income tax, it has the
characteristics of an income tax since it is determined by applying a tax rate
to a base that considers both revenues and expenses. Due to the
enactment of the Texas Margin Tax, we recorded a net deferred tax asset of $0.3
million during the year ended December 31, 2009.
Litigation
On
occasion, we or our unconsolidated affiliates are named as defendants in
litigation and legal proceedings relating to our normal business activities,
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.
We
evaluate our ongoing litigation based upon a combination of litigation and
settlement alternatives. These reviews are updated as the facts and
combinations of the cases develop or change. Assessing and predicting
the outcome of these matters involves substantial uncertainties. In
the event that the assumptions we used to evaluate these matters change in
future periods or new information becomes available, we may be required to
record a liability for an adverse outcome. In an effort to mitigate
potential adverse consequences of litigation, we could also seek to settle legal
proceedings brought against us. We have not recorded any significant
reserves for any litigation on our balance sheet.
On
September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed
a complaint in the Court of Chancery of the State of Delaware (the “Delaware
Court”), in his individual capacity, as a putative class action on behalf of
other unitholders of TEPPCO and derivatively on behalf of TEPPCO, concerning,
among other things, certain transactions involving TEPPCO and Enterprise
Products Partners or its affiliates. Mr. Brinckerhoff filed an
amended complaint on July 12, 2007. The amended complaint names as
defendants (i) TEPPCO, certain of its current and former directors, and certain
of its affiliates, (ii) Enterprise Products Partners and certain of its
affiliates, (iii) EPCO and (iv) Dan L. Duncan.
The amended complaint alleges, among
other things, that the defendants caused TEPPCO to enter into specified
transactions that were unfair to TEPPCO or otherwise unfairly favored Enterprise
Products Partners or its affiliates over TEPPCO. These transactions
are alleged to include: (i) the joint venture to further expand the Jonah system
entered into by TEPPCO and Enterprise Products Partners in August 2006 (the
plaintiff alleges that TEPPCO did not receive fair value for allowing Enterprise
Products Partners to participate in the joint venture); (ii) the sale by TEPPCO
of its Pioneer natural gas processing plant and certain gas processing rights to
Enterprise Products Partners in March 2006 (the plaintiff alleges that the
purchase price we paid did not provide fair value to TEPPCO) and (iii) certain
amendments to TEPPCO’s partnership agreement, including a reduction in the
maximum tier of TEPPCO’s incentive distribution rights in exchange for TEPPCO
units. The amended complaint seeks (i) rescission of the amendments
to TEPPCO’s partnership agreement, (ii) damages for profits and special benefits
allegedly obtained by defendants as a result of the alleged wrongdoings in the
amended complaint and (iii) an award to plaintiff of the costs of the action,
including fees and expenses of his attorneys and experts. By its
Opinion and Order dated November 25, 2008, the Delaware Court dismissed Mr.
Brinckerhoff’s individual and putative class action claims with respect to the
amendments to TEPPCO’s partnership agreement. We refer to this action
and the remaining claims in this action as the “Derivative Action.”
On April 29, 2009, Peter Brinckerhoff
and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of
TEPPCO, filed separate complaints in the Delaware Court as putative class
actions on behalf of other unitholders of TEPPCO, concerning the TEPPCO
Merger. On May 11, 2009, these actions were consolidated under the
caption Texas Eastern Products Pipeline Company, LLC Merger Litigation, C.A. No.
4548-VCL (“Merger Action”). The complaints name as defendants
Enterprise Products Partners, EPGP, TEPPCO GP, the directors of TEPPCO GP, EPCO
and Dan L. Duncan.
The Merger Action complaints allege,
among other things, that the terms of the merger (as proposed as of the time the
Merger Action complaints were filed) are grossly unfair to TEPPCO’s unitholders
and that the TEPPCO Merger is an attempt to extinguish the Derivative Action
without consideration. The complaints further allege that the process
through which the Special Committee of the
ACG
Committee of TEPPCO GP was appointed to consider the TEPPCO Merger is contrary
to the spirit and intent of TEPPCO’s partnership agreement and constitutes a
breach of the implied covenant of fair dealing.
The complaints seek relief (i)
enjoining the defendants and all persons acting in concert with them from
pursuing the TEPPCO Merger, (ii) rescinding the TEPPCO Merger to the extent it
is consummated, or awarding rescissory damages in respect thereof, (iii)
directing the defendants to account for all damages suffered or to be suffered
by the plaintiffs and the purported class as a result of the defendants’ alleged
wrongful conduct, and (iv) awarding plaintiffs’ costs of the actions, including
fees and expenses of their attorneys and experts.
On August 5, 2009, the parties entered
into a Stipulation and Agreement of Compromise, Settlement and Release (the
“Settlement Agreement”). Pursuant to the Settlement Agreement, the
board of directors of TEPPCO GP recommended to TEPPCO’s unitholders that they
approve the adoption of the merger agreement and took all necessary steps to
seek unitholder approval for the merger.
The
Delaware Court approved the Settlement Agreement on January 15, 2010, dismissing
with prejudice the Merger Action and the Derivative Action.
Additionally, on June 29 and 30, 2009,
respectively, M. Lee Arnold and Sharon Olesky, purported unitholders of TEPPCO,
filed separate complaints in the District Courts of Harris County, Texas, as
putative class actions on behalf of other unitholders of TEPPCO, concerning the
TEPPCO Merger (the “Texas Actions”). The complaints name as
defendants Enterprise Products Partners, TEPPCO, TEPPCO GP, EPGP, EPCO, Dan L.
Duncan, Jerry Thompson, and the board of directors of TEPPCO GP. The
allegations in the complaints are similar to the complaints filed in Delaware on
April 29, 2009 and seek similar relief. The named plaintiffs in the
two Texas Actions (the “Texas Plaintiffs/Objectors”) also appeared in the
Delaware proceedings as objectors to the settlement of those cases which were
then awaiting court approval. On October 7, 2009, the Texas
Plaintiffs/Objectors and the parties to the Settlement Agreement entered into a
Stipulation to Withdraw Objection (the “Stipulation”). In accordance
with the Stipulation, and upon the receipt of Final Court Approval (as defined
in the Settlement Agreement), the Texas Plaintiffs/Objectors agreed to dismiss
the Texas Actions with prejudice. As of March 1, 2010, the Texas
Actions have been dismissed with prejudice pursuant to the Settlement
Agreement.
In
February 2007, EPO received a letter from the Environment and Natural Resources
Division of the U.S. Department of Justice related to an ammonia release in
Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia
pipeline owned by a third-party, Magellan Ammonia Pipeline, L.P. (“Magellan”),
and a previous release of ammonia on September 27, 2004 from the same
pipeline. EPO was the operator of this pipeline until July 1,
2008. This matter was settled in September 2009, and Magellan has
agreed to pay all assessed penalties.
The Attorney General of Colorado on
behalf of the Colorado Department of Public Health and Environment (“CDPHE”)
filed suit against Enterprise Products Partners and others on April 15, 2008 in
connection with the construction of a pipeline near Parachute, Colorado.
The State sought a temporary restraining order and an injunction to halt
construction activities since it alleged that the defendants failed to install
measures to minimize damage to the environment and to follow requirements for
the pipeline’s storm water permit and appropriate storm water plan. We have
entered into a settlement agreement with the State that dismisses the suit and
assesses a fine of approximately $0.2 million.
The
CDPHE, through its Air Pollution Control Division, has proposed a Compliance
Order on Consent with Enterprise Gas Processing, L.L.C for alleged violations of
the Colorado Air Pollution and Prevention and Control Act (“Colorado Act”) with
respect to operations of the Meeker Gas Processing Plant. The
Compliance Order proposes an administrative fine of approximately $0.3 million
and would require the Meeker Gas Processing Plant to be operated in compliance
with the Colorado Act. Enterprise Products Partners has entered into
discussions regarding the terms of the Compliance Order.
In
January 2009, the State of New Mexico filed suit in District Court in Santa Fe
County, New Mexico, under the New Mexico Air Quality Control Act. The
lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon
Oil Corp. (“Marathon”) as operator of the Indian Basin natural gas processing
facility located in Eddy County, New Mexico. We own a 42.4% undivided
interest in the assets comprising the Indian Basin facility. The
State alleges violations of its air laws. Marathon agreed to a
Consent Decree with the State which was approved by the District Court on
December 21, 2009. Under the Decree, Marathon paid the State approximately
$0.6 million, agreed to $4.5 million of additional environmental projects in New
Mexico and agreed to two projects for “corrective measures” at the
facility. We are in discussions with Marathon regarding the
responsibility for these payments. We believe that any potential
payment we make will not have a material impact on our consolidated financial
position.
In
connection with our dissociation from TOPS (see Note 7), Oiltanking filed an
original petition against Enterprise Offshore Port System, LLC, EPO, TEPPCO O/S
Port System, LLC, TEPPCO and TEPPCO GP in the District Court of Harris County,
Texas, 61st Judicial District (Cause No. 2009-31367), asserting, among other
things, that the dissociation was wrongful and in breach of the TOPS partnership
agreement, citing provisions of the agreement that, if applicable, would
continue to obligate us and TEPPCO to make capital contributions to fund the
project and impose liabilities on us and TEPPCO. On September 17,
2009, we and TEPPCO entered into a settlement agreement with certain affiliates
of Oiltanking and TOPS that resolved all disputes between the parties related to
the business and affairs of the TOPS project (including the litigation described
above). We recognized approximately $66.9 million of expense (as
reflected in equity) during 2009 in connection with this
settlement. This charge is classified within our Offshore Pipelines
& Services business segment.
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 may have an adverse effect on
our business, financial position and demand for our operations.
Contractual
Obligations
The
following table summarizes our various contractual obligations at December 31,
2009. A description of each type of contractual obligation
follows:
|
Payment
or Settlement due by Period
|
||||||||||||||||||||||||||||
|
Contractual
Obligations
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
|||||||||||||||||||||
|
Scheduled
maturities of long-term debt
|
$ | 11,297.0 | $ | 554.0 | $ | 907.3 | $ | 1,195.5 | $ | 1,200.0 | $ | 1,150.0 | $ | 6,290.2 | ||||||||||||||
|
Estimated
cash interest payments
|
$ | 12,372.2 | $ | 667.4 | $ | 618.3 | $ | 571.9 | $ | 502.9 | $ | 436.5 | $ | 9,575.2 | ||||||||||||||
|
Operating
lease obligations
|
$ | 343.9 | $ | 37.6 | $ | 35.3 | $ | 32.7 | $ | 27.3 | $ | 21.5 | $ | 189.5 | ||||||||||||||
|
Purchase
obligations:
|
||||||||||||||||||||||||||||
|
Product
purchase commitments:
|
||||||||||||||||||||||||||||
|
Estimated
payment obligations:
|
||||||||||||||||||||||||||||
|
Natural
gas
|
$ | 5,697.6 | $ | 1,308.9 | $ | 685.5 | $ | 696.3 | $ | 487.5 | $ | 471.8 | $ | 2,047.6 | ||||||||||||||
|
NGLs
|
$ | 2,943.0 | $ | 997.0 | $ | 339.3 | $ | 329.8 | $ | 329.7 | $ | 329.7 | $ | 617.5 | ||||||||||||||
|
Crude
oil
|
$ | 237.3 | $ | 237.3 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
Petrochemicals
& refined products
|
$ | 2,642.2 | $ | 1,486.6 | $ | 586.0 | $ | 238.5 | $ | 113.9 | $ | 72.4 | $ | 144.8 | ||||||||||||||
|
Other
|
$ | 114.1 | $ | 21.2 | $ | 12.2 | $ | 11.9 | $ | 11.8 | $ | 11.0 | $ | 46.0 | ||||||||||||||
|
Underlying
major volume commitments:
|
||||||||||||||||||||||||||||
|
Natural
gas (in BBtus) (1)
|
969,180 | 221,530 | 114,304 | 116,146 | 83,854 | 81,154 | 352,192 | |||||||||||||||||||||
|
NGLs
(in MBbls) (2)
|
49,300 | 19,048 | 5,337 | 5,159 | 5,158 | 5,158 | 9,440 | |||||||||||||||||||||
|
Crude
oil (in MBbls) (2)
|
2,985 | 2,985 | -- | -- | -- | -- | -- | |||||||||||||||||||||
|
Petrochemicals
& refined products (in MBbls)
|
35,034 | 19,523 | 7,856 | 3,266 | 1,509 | 960 | 1,920 | |||||||||||||||||||||
|
Service
payment commitments
|
$ | 575.6 | $ | 72.0 | $ | 57.0 | $ | 56.7 | $ | 55.1 | $ | 55.0 | $ | 279.8 | ||||||||||||||
|
Capital
expenditure commitments
|
$ | 497.5 | $ | 497.5 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
|
(1) Volume
is measured in billion British thermal units (“BBtus”).
(2) Volume
is measured in thousands of barrels (“MBbls”).
|
||||||||||||||||||||||||||||
Scheduled
Maturities of Long-Term Debt. We have
long-term and short-term payment obligations under debt
agreements. Amounts shown in the preceding table represent our
scheduled future maturities of debt principal for the periods
indicated. See Note 11 for additional information regarding our
consolidated debt obligations.
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, (ii) leased office space with affiliates of
EPCO and (iii) land held pursuant to right-of-way agreements. In
general, our material lease agreements have current terms that range from 14 to
20 years. The agreements for leased office space with affiliates of
EPCO and underground NGL storage caverns we lease from a third party include
renewal options that could extend these contracts for up to an additional 20
years. The remainder of our material lease agreements do not provide
for additional renewal terms.
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. We
did not make any significant leasehold improvements during the year ended
December 31, 2009.
The
operating lease commitments shown in the preceding table exclude the non-cash,
related party expense associated with retained leases contributed to us by EPCO
in 1998. EPCO remains liable for the actual cash lease payments
associated with these agreements, which it accounts for as operating
leases. At December 31, 2009, the retained leases were for
approximately 100 railcars. EPCO’s minimum future rental payments
under these leases are $0.7 million for each of the years 2010 through 2015 and
$0.3 million for 2016. We record the full value of these payments
made by EPCO on our behalf as a non-cash related party operating lease expense,
with the offset to equity accounted for as a general contribution to our
partnership.
The
retained lease agreements contain lessee purchase options, which are at prices
that approximate fair value of the underlying leased assets. EPCO has
assigned these purchase options to us. Should we decide to exercise
the purchase option associated with the agreement, we would pay the original
lessor $3.1 million in June 2016.
Purchase
Obligations.
We
define a purchase obligation as an agreement to purchase goods or services that
is enforceable and legally binding (unconditional) on us that specifies 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 classified our unconditional purchase
obligations into the following categories:
|
§
|
We
have long and short-term product purchase obligations for natural gas,
NGLs, crude oil, refined products and certain petrochemicals with
third-party suppliers. 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 under each contract for purchases made
at December 31, 2009 applied to all future volume
commitments. Actual future payment obligations may vary
depending on prices at the time of delivery. At December 31,
2009, we do not have any significant product purchase commitments with
fixed or minimum pricing provisions with remaining terms in excess of one
year.
|
|
§
|
We
have long and short-term commitments to pay third-party providers for
services. Our contractual service payment commitments primarily
represent our obligations under firm pipeline transportation contracts on
pipelines owned by third parties. Payment obligations vary by
contract, but generally represent a price per unit of volume multiplied by
a firm transportation volume commitment. The preceding table
shows our estimated future payment obligations under these service
contracts.
|
|
§
|
We
have short-term payment obligations relating to our capital projects and
those of our unconsolidated affiliates. These commitments
represent unconditional payment obligations to vendors for services
rendered or products purchased. The preceding table presents
our share of such commitments for the periods
indicated.
|
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 14). See Note 4 for additional information
regarding our accounting for equity awards.
Other
Claims
As part
of our normal business activities with joint venture partners, customers and
suppliers, we occasionally have claims made against us as a result of disputes
related to contractual agreements. As of December 31, 2009, claims
against us totaled approximately $21.1 million. These matters are in
various stages of assessment and the ultimate outcome of such disputes cannot be
reasonably estimated. However, in our opinion, the likelihood of a
material adverse outcome related to disputes against us is
remote. Accordingly, accruals for loss contingencies related to these
matters that might result from the resolution of such disputes have not been
reflected in our Consolidated Balance Sheet.
Other
Commitments
We
transport and store natural gas, NGLs and petrochemicals for third parties under
various processing, storage, transportation and similar
agreements. These volumes are either accrued as product payables, in
transit for delivery to our customers or held at our storage facilities for
redelivery to our
customers. Under
terms of our storage agreements, we are generally required to redeliver volumes
to the owner on demand. At December 31, 2009, NGL and petrochemical
products aggregating 29.8 million barrels were due to be redelivered to their
owners along with 17,112 BBtus of natural gas. See Note 2 for more
information regarding accrued product payables.
Centennial
Guarantees
We have
certain guarantee obligations in connection with our ownership interest in
Centennial. We have guaranteed one-half of Centennial’s debt
obligations, which obligates us to an estimated payment of $60.0 million in the
event of a default by Centennial. At December 31, 2009, we had a
liability of $8.4 million representing the estimated fair value of our share of
the Centennial debt guaranty. See Note 11 for information regarding
Centennial’s debt obligations.
In lieu
of Centennial procuring insurance to satisfy third-party liabilities arising
from a catastrophic event, we and Centennial’s other joint venture partner have
entered a limited cash call agreement. We are obligated to contribute
up to a maximum of $50.0 million (in proportion to our ownership interest in
Centennial) in the event of a catastrophic event. At December 31,
2009, we had a liability of $3.6 million representing the estimated fair value
of our cash call guaranty. Cash contributions to Centennial under the
limited cash call agreement may be covered by our insurance depending on the
nature of the catastrophic event.
Nature
of Operations in Midstream Energy Industry
Our operations are within the midstream
energy industry, which includes gathering, transporting, processing,
fractionating and storing natural gas, NGLs, crude oil, refined products and
certain petrochemicals. We also market natural gas, NGLs, crude oil
and other hydrocarbon products. As such, our 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 (e.g.,
natural gas processing margins are influenced by the ratio of natural gas prices
to crude oil prices). The prices of hydrocarbon products are subject
to fluctuation 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 gathered, transported, processed, fractionated or stored 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, NGLs, refined products and crude oil
handled by our facilities.
A reduction in demand for natural gas,
crude oil, NGL and other hydrocarbon 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 such products, (iii)
increased competition from other 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 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. 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 Enterprise Products Partners ability to pay distributions to our partners
and, accordingly, adversely affect the market price of its 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. With respect to
offshore assets, the windstorm deductible is $75.0 million per
storm. EPCO’s offshore program currently provides $100.0 million in
the aggregate. For non-windstorm events, EPCO’s deductible for both
onshore and offshore physical damage is $5.0 million per occurrence. For
certain of our major offshore assets, our producer customers have agreed to
provide a specified level of physical damage insurance for named
windstorms. For example, the producers associated with our
Independence Hub and Marco Polo platforms have agreed to cover windstorm
generated physical damage costs up to $250.0 million for each
platform.
Business
interruption coverage in connection with a windstorm event remains in place for
onshore assets, but was eliminated for offshore assets. Onshore
assets covered by business interruption insurance must be out-of-service in
excess of 60 days before any losses from business interruption 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.
The
following table summarizes proceeds we received from weather-related business
interruption and property damage insurance claims during the year ended December
31, 2009:
|
Business
interruption proceeds:
|
||||
|
Hurricanes
Gustav and Ike in 2008
|
$ | 33.2 | ||
|
Total
proceeds
|
33.2 | |||
|
Property
damage proceeds:
|
||||
|
Hurricanes
Katrina and Rita in 2005
|
38.6 | |||
|
Hurricanes
Gustav and Ike in 2008
|
15.1 | |||
|
Other
|
0.7 | |||
|
Total
proceeds
|
54.4 | |||
|
Total
|
$ | 87.6 | ||
At
December 31, 2009, we have $37.6 million of estimated property damage claims
outstanding related to these storms that we believe are probable of collection
through 2010. To the extent we estimate the dollar value of such
damages, please be aware that a change in our estimates may occur as additional
information becomes available.
Enterprise
Products Partners Issues $343.1 Million of Common Units
In
January 2010, Enterprise Products Partners issued 10,925,000 common units
(including an over-allotment of 1,425,000 common units) to the public at an
offering price of $32.42 per unit. Enterprise Products Partners used
the net cash proceeds of $343.1 million to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility, which may be
reborrowed to fund capital expenditures and other growth projects, and for
general partnership purposes.
54