UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
10-Q
þ QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
quarterly period ended March 31, 2009
OR
o TRANSITION REPORT PURSUANT
TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
transition period from ___ to ___.
Commission
file number: 1-10403
TEPPCO
Partners, L.P.
(Exact
name of Registrant as Specified in Its Charter)
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Delaware
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76-0291058
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(State
or Other Jurisdiction of
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(I.R.S.
Employer Identification No.)
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Incorporation
or Organization)
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1100
Louisiana Street, Suite 1600
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Houston,
Texas 77002
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(Address
of Principal Executive Offices, Including Zip Code)
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(713)
381-3636
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(Registrant’s
Telephone Number, Including Area Code)
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Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
| Yes þ No o |
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files).
| Yes ¨ No ¨ |
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of “large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
| Large accelerated filer þ | Accelerated filer o | |
| Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
| Yes o No þ |
There
were 104,767,316 limited partner units of TEPPCO Partners, L.P. outstanding at
May 1, 2009. These limited partner units trade on the New York Stock
Exchange under the ticker symbol “TPP.”
TABLE
OF CONTENTS
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Page
No.
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2
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3
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4
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5
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6
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7
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8
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8
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11
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15
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15
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16
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17
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18
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19
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24
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27
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28
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33
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33
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37
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39
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39
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57
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58
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59
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59
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60
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60
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62
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TEPPCO
PARTNERS, L.P.
(Dollars
in millions)
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March
31,
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December
31,
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ASSETS
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2009
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2008
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Current
assets:
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Cash and cash equivalents
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$ | 2.2 | $ | -- | ||||
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Accounts receivable, trade (net of allowance for doubtful accounts
of
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||||||||
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$2.6 at March 31, 2009 and December 31, 2008)
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741.6 | 790.4 | ||||||
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Accounts receivable, related parties
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10.7 | 15.8 | ||||||
| Inventories | 52.6 | 52.9 | ||||||
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Other
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33.4 | 48.5 | ||||||
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Total current assets
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840.5 | 907.6 | ||||||
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Property, plant
and equipment, at cost (net of accumulated depreciation
of
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$703.8 at March 31, 2009 and $678.8 at December 31,
2008)
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2,517.2 | 2,439.9 | ||||||
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Investments
in unconsolidated affiliates
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1,244.8 | 1,255.9 | ||||||
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Intangible
assets (net of accumulated amortization of $165.1
at
March 31, 2009 and $158.3 at December 31, 2008)
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202.3 | 207.7 | ||||||
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Goodwill
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106.6 | 106.6 | ||||||
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Other
assets
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131.3 | 132.1 | ||||||
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Total assets
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$ | 5,042.7 | $ | 5,049.8 | ||||
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LIABILITIES
AND PARTNERS’ CAPITAL
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Current
liabilities:
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Accounts payable and accrued liabilities
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$ | 755.2 | $ | 792.5 | ||||
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Accounts payable, related parties
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20.6 | 17.2 | ||||||
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Accrued interest
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45.7 | 36.4 | ||||||
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Other accrued taxes
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18.0 | 23.0 | ||||||
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Other
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14.9 | 30.9 | ||||||
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Total current liabilities
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854.4 | 900.0 | ||||||
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Long-term
debt:
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||||||||
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Senior
notes
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1,712.1 | 1,713.3 | ||||||
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Junior
subordinated notes
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299.6 | 299.6 | ||||||
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Other
long-term debt
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565.6 | 516.7 | ||||||
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Total
long-term debt
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2,577.3 | 2,529.6 | ||||||
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Other
liabilities and deferred credits
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28.5 | 28.7 | ||||||
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Commitments
and contingencies
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Partners’
capital:
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Limited partners’ interests:
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Limited partner units (104,618,116 units outstanding at March 31,
2009
and 104,547,561 units outstanding at December 31,
2008)
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1,737.7 | 1,746.2 | ||||||
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Restricted limited partner units (149,200 units outstanding
at March 31,
2009 and 157,300 units outstanding at December 31,
2008)
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1.7 | 1.4 | ||||||
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General partner’s interest
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(112.5 | ) | (110.3 | ) | ||||
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Accumulated other comprehensive loss
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(44.4 | ) | (45.8 | ) | ||||
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Total partners’ capital
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1,582.5 | 1,591.5 | ||||||
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Total liabilities and partners’ capital
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$ | 5,042.7 | $ | 5,049.8 | ||||
See Notes
to Unaudited Condensed Consolidated Financial Statements.
TEPPCO
PARTNERS, L.P.
(Dollars
in millions, except per unit amounts)
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For
the Three Months
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Ended
March 31,
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2009
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2008
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Operating
revenues:
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Sales
of petroleum products
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$ | 1,277.9 | $ | 2,644.6 | ||||
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Transportation
– Refined products
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35.9 | 37.3 | ||||||
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Transportation
– LPGs
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38.3 | 36.2 | ||||||
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Transportation
– Crude oil
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21.9 | 15.3 | ||||||
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Transportation
– NGLs
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12.5 | 13.0 | ||||||
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Transportation
– Marine
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36.9 | 25.5 | ||||||
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Gathering
– Natural gas
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13.6 | 13.4 | ||||||
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Other
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20.6 | 23.2 | ||||||
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Total
operating revenues
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1,457.6 | 2,808.5 | ||||||
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Costs and expenses:
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Purchases
of petroleum products
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1,235.5 | 2,606.6 | ||||||
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Operating
expense
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66.8 | 53.8 | ||||||
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Operating
fuel and power
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19.7 | 21.4 | ||||||
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General
and administrative
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10.0 | 8.8 | ||||||
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Depreciation
and amortization
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33.0 | 28.3 | ||||||
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Taxes
– other than income taxes
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6.9 | 6.1 | ||||||
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Total
costs and expenses
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1,371.9 | 2,725.0 | ||||||
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Operating
income
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85.7 | 83.5 | ||||||
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Other
income (expense):
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Interest
expense
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(32.1 | ) | (38.6 | ) | ||||
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Equity
in earnings of unconsolidated affiliates
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25.1 | 19.7 | ||||||
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Other,
net
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0.3 | 0.3 | ||||||
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Income
before provision for income taxes
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79.0 | 64.9 | ||||||
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Provision
for income taxes
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0.8 | 0.8 | ||||||
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Net
income
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$ | 78.2 | $ | 64.1 | ||||
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Net
income allocation:
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Limited
partners’ interest in net income
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$ | 65.0 | $ | 53.4 | ||||
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General
partner’s interest in net income
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$ | 13.2 | $ | 10.7 | ||||
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Earnings
per unit, basic and diluted
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$ | 0.62 | $ | 0.57 | ||||
See Notes
to Unaudited Condensed Consolidated Financial Statements.
TEPPCO
PARTNERS, L.P.
COMPREHENSIVE
INCOME
(Dollars
in millions)
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For
the Three Months
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||||||||
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Ended
March 31,
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2009
|
2008
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Net
income
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$ | 78.2 | $ | 64.1 | ||||
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Other
comprehensive income (loss):
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||||||||
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Cash
flow hedges: (see Note 4)
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Change
in fair values of interest rate derivative instruments
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-- | (23.2 | ) | |||||
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Reclassification
adjustment for loss included in net income
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||||||||
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related
to interest rate derivative instruments
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1.4 | -- | ||||||
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Changes
in fair values of commodity derivative instruments
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-- | (6.5 | ) | |||||
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Reclassification
adjustment for loss included in net income
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||||||||
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related
to commodity derivative instruments
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-- | 9.6 | ||||||
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Total
cash flow hedges
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1.4 | (20.1 | ) | |||||
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Total
other comprehensive income (loss)
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1.4 | (20.1 | ) | |||||
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Comprehensive
income
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$ | 79.6 | $ | 44.0 | ||||
See Notes
to Unaudited Condensed Consolidated Financial Statements.
TEPPCO
PARTNERS, L.P.
(Dollars
in millions)
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For
the Three Months
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||||||||
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Ended
March 31,
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2009
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2008
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Operating
activities:
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||||||||
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Net
income
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$ | 78.2 | $ | 64.1 | ||||
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Adjustments
to reconcile net income to cash provided by operating
activities:
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Depreciation and amortization
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33.0 | 28.3 | ||||||
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Amortization of deferred compensation
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0.2 | 0.3 | ||||||
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Amortization in interest expense
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0.7 | 2.9 | ||||||
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Changes in fair market value of derivative instruments
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(0.6 | ) | (0.4 | ) | ||||
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Equity in earnings of unconsolidated affiliates
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(25.1 | ) | (19.7 | ) | ||||
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Distributions received from unconsolidated affiliates
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47.7 | 37.2 | ||||||
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Loss on early extinguishment of debt
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-- | 8.7 | ||||||
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Net effect of changes in operating accounts (see Note 15)
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22.5 | (62.7 | ) | |||||
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Net
cash provided by operating activities
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156.6 | 58.7 | ||||||
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Investing
activities:
|
||||||||
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Cash
used for business combinations
|
-- | (338.5 | ) | |||||
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Investment
in Jonah Gas Gathering Company
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(12.3 | ) | (31.8 | ) | ||||
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Investment
in Texas Offshore Port System (see Notes 7 and 17)
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1.7 | -- | ||||||
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Acquisition
of intangible assets
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(1.4 | ) | (0.3 | ) | ||||
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Cash
paid for linefill classified as other assets
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-- | (14.3 | ) | |||||
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Capital
expenditures
|
(101.6 | ) | (51.6 | ) | ||||
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Net
cash used in investing activities
|
(113.6 | ) | (436.5 | ) | ||||
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Financing
activities:
|
||||||||
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Borrowings
under debt agreements
|
301.8 | 2,512.6 | ||||||
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Repayments
of debt
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(252.8 | ) | (2,001.8 | ) | ||||
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Net
proceeds from issuance of limited partner units
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1.6 | 2.7 | ||||||
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Debt
issuance costs
|
-- | (8.7 | ) | |||||
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Settlement
of interest rate derivative instruments - treasury locks
|
-- | (52.1 | ) | |||||
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Distributions
paid to partners
|
(91.4 | ) | (74.9 | ) | ||||
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Net
cash provided by (used in) financing activities
|
(40.8 | ) | 377.8 | |||||
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Net
change in cash and cash equivalents
|
2.2 | -- | ||||||
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Cash
and cash equivalents, January 1
|
-- | -- | ||||||
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Cash
and cash equivalents, March 31
|
$ | 2.2 | $ | -- | ||||
See Notes
to Unaudited Condensed Consolidated Financial Statements.
TEPPCO
PARTNERS, L.P.
(Dollars
in millions)
|
Limited
|
General
|
|||||||||||||||
|
Partners
|
Partner
|
AOCI
|
Total
|
|||||||||||||
|
Balance,
December 31, 2008
|
$ | 1,747.6 | $ | (110.3 | ) | $ | (45.8 | ) | $ | 1,591.5 | ||||||
|
Net
proceeds from issuance of limited partner units
|
1.6 | -- | -- | 1.6 | ||||||||||||
|
Net income
|
65.0 | 13.2 | -- | 78.2 | ||||||||||||
|
Distributions paid to partners
|
(76.0 | ) | (15.4 | ) | -- | (91.4 | ) | |||||||||
|
Non-cash contributions
|
0.2 | -- | -- | 0.2 | ||||||||||||
|
Amortization of equity awards
|
1.0 | -- | -- | 1.0 | ||||||||||||
|
Reclassification adjustment for loss included in net
|
||||||||||||||||
|
income related to interest rate derivative
instruments
|
-- | -- | 1.4 | 1.4 | ||||||||||||
|
Balance,
March 31, 2009
|
$ | 1,739.4 | $ | (112.5 | ) | $ | (44.4 | ) | $ | 1,582.5 | ||||||
|
Limited
|
General
|
|||||||||||||||
|
Partners
|
Partner
|
AOCI
|
Total
|
|||||||||||||
|
Balance,
December 31, 2007
|
$ | 1,395.2 | $ | (88.0 | ) | $ | (42.6 | ) | $ | 1,264.6 | ||||||
|
Net proceeds from issuance of limited partner units
|
2.7 | -- | -- | 2.7 | ||||||||||||
|
Issuance of limited partner units in connection with
Cenac acquisition on February 1, 2008
|
186.6 | -- | -- | 186.6 | ||||||||||||
|
Net income
|
53.4 | 10.7 | -- | 64.1 | ||||||||||||
|
Distributions paid to partners
|
(62.5 | ) | (12.4 | ) | -- | (74.9 | ) | |||||||||
|
Non-cash contributions
|
0.1 | -- | -- | 0.1 | ||||||||||||
|
Amortization of equity awards
|
0.2 | -- | -- | 0.2 | ||||||||||||
|
Changes in fair values of commodity derivative
instruments
|
-- | -- | (6.5 | ) | (6.5 | ) | ||||||||||
|
Reclassification adjustment for loss included in net
income related to commodity derivative instruments
|
-- | -- | 9.6 | 9.6 | ||||||||||||
|
Changes in fair values of interest rate derivative
instruments
|
-- | -- | (23.2 | ) | (23.2 | ) | ||||||||||
|
Balance,
March 31, 2008
|
$ | 1,575.7 | $ | (89.7 | ) | $ | (62.7 | ) | $ | 1,423.3 | ||||||
See Notes
to Unaudited Condensed Consolidated Financial Statements.
6
Except
per unit amounts, or 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.
Partnership
Organization
TEPPCO Partners, L.P. is a publicly
traded, diversified energy logistics partnership with operations that span much
of the continental United States. Our limited partner units (“Units”)
are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol
“TPP”. We were formed in March 1990 as a Delaware limited
partnership. As used in this Report, “we,” “us,” “our,” the
“Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context
requires, include our subsidiaries.
We operate through TE Products Pipeline
Company, LLC (“TE Products”), TCTM, L.P. (“TCTM”), TEPPCO Midstream Companies,
LLC (“TEPPCO Midstream”), and beginning February 1, 2008, through TEPPCO Marine
Services, LLC (“TEPPCO Marine Services”). Texas Eastern Products Pipeline
Company, LLC (the “General Partner”), a Delaware limited liability company,
serves as our general partner and owns a 2% general partner interest in
us. We hold a 99.999% limited partner interest in TCTM, 99.999%
membership interests in each of TE Products and TEPPCO Midstream and a 100%
membership interest in TEPPCO Marine Services. TEPPCO GP, Inc., our
subsidiary, holds a 0.001% general partner interest in TCTM and a 0.001%
managing member interest in each of TE Products and TEPPCO
Midstream.
Dan L. Duncan and certain of his
affiliates, including Enterprise GP Holdings L.P. (“Enterprise GP Holdings”) and
Dan Duncan LLC, a privately held company controlled by him, control us, our
General Partner and Enterprise Products Partners L.P. (“Enterprise Products
Partners”) and its affiliates, including Duncan Energy Partners L.P. (“Duncan
Energy Partners”). Enterprise GP Holdings owns and controls the 2%
general partner interest in us and has the right (through its 100% ownership of
our General Partner) to receive the incentive distribution rights associated
with the general partner interest. Enterprise GP Holdings, DFI GP
Holdings L.P. (“DFIGP”) and other entities controlled by Mr. Duncan own
17,073,315 of our Units, which include 2,500,000 of our Units owned by
DFIGP. Under an amended and restated administrative services
agreement (“ASA”), EPCO, Inc. (“EPCO”), a privately held company also controlled
by Mr. Duncan, performs management, administrative and operating functions
required for us, and we reimburse EPCO for all direct and indirect expenses that
have been incurred in managing us.
We refer to refined products, liquefied
petroleum gases (“LPGs”), petrochemicals, crude oil, lubrication oils and
specialty chemicals, natural gas liquids (“NGLs”), natural gas, asphalt, heavy
fuel oil and other heated oil products, collectively as “petroleum products” or
“products.”
Basis
of Presentation
The accompanying unaudited condensed
consolidated financial statements reflect all adjustments that are, in the
opinion of our management, of a normal and recurring nature and necessary for a
fair statement of our financial position as of March 31, 2009, and the results
of our operations and cash flows for the periods presented. The
results of operations for the three months ended March 31, 2009 are not
necessarily indicative of results of our operations for the full year
2009. The unaudited condensed consolidated financial statements have
been prepared pursuant to the rules and regulations of the U.S. Securities and
Exchange Commission (“SEC”). Certain information and note disclosures
normally included in annual financial statements prepared in accordance with
U.S. generally accepted accounting principles (“GAAP”) have been condensed or
omitted pursuant to those rules and regulations. You should read
these interim financial statements in conjunction with our consolidated
financial statements and notes thereto presented in the TEPPCO Partners, L.P.
Annual Report on Form 10-K for the year ended December 31,
2008.
7
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Estimates
The preparation of financial statements
in conformity with GAAP requires our management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Although we believe these estimates are reasonable, actual
results could differ from those estimates.
Recent
Accounting Developments
The following information summarizes
recently issued accounting guidance since those reported in our Annual Report on
Form 10-K for the year ended December 31, 2008 that will or may affect our
future financial statements.
In April 2009, the Financial Accounting
Standards Board (“FASB”) issued new guidance in the form of FASB Staff Positions
(“FSPs”) in an effort to clarify certain fair value accounting rules. FSP
FAS 157-4, Determining
Fair Value When the
Volumes and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly, establishes
a process to determine whether a market is not active and a transaction is not
distressed. FSP FAS 157-4 states that companies should look at
several factors and use judgment to ascertain if a formerly active market has
become inactive. When estimating fair value, FSP FAS 157-4 requires
companies to place more weight on observable transactions determined to be
orderly and less weight on transactions for which there is insufficient
information to determine whether the transaction is orderly (entities do not
have to incur undue cost and effort in making this determination). The FASB also
issued FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value
of Financial Instruments. This FSP requires that companies provide
qualitative and quantitative information about fair value estimates for all
financial instruments not measured on the balance sheet at fair value in each
interim report. Previously, this was only an annual requirement. We
will adopt these FSPs effective July 1, 2009. We do not expect that
this new guidance will have a material impact on our financial
statements.
We account for equity awards in
accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123(R),
Share-Based Payment
(“SFAS 123(R)”). Such awards were not material to our consolidated
financial position, results of operations or cash flows for all periods
presented. The amount of equity-based compensation allocable to our
consolidated businesses was $1.0 million and $0.3 million for the three months
ended March 31, 2009 and 2008, respectively.
Certain key employees of EPCO
participate in long-term incentive compensation plans managed by
EPCO. The compensation expense we record related to equity awards is
based on an allocation of the total cost of such incentive plans to
EPCO. We record our pro rata share of such costs based on the
percentage of time each employee spends on our consolidated business
activities.
1999
Phantom Unit Retention Plan
The Texas Eastern Products Pipeline
Company, LLC 1999 Phantom Unit Retention Plan (“1999 Plan”) provides for the
issuance of phantom unit awards as incentives to key employees. A
total of 15,800 phantom units were outstanding under the 1999 Plan at March 31,
2009, as 2,800 additional phantom units outstanding at December 31, 2008 under
the 1999 Plan were forfeited during the three months ended March 31,
2009. The 15,800 outstanding phantom unit awards cliff vest as
follows: 13,000 in April 2009 and
8
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2,800 in
January 2010. At March 31, 2009 and December 31, 2008, we had
accrued liability balances of $0.4 million for compensation related to the 1999
Plan.
2000
Long Term Incentive Plan
The Texas Eastern Products Pipeline
Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) provides key employees
incentives to achieve improvements in our financial performance. At
December 31, 2008, we had an accrued liability balance of $0.2 million for
compensation related to the 2000 LTIP. On December 31, 2008, 11,300
phantom units vested and $0.2 million was paid out to participants in the first
quarter of 2009. There were no remaining phantom units outstanding
under the 2000 LTIP at March 31, 2009.
2005
Phantom Unit Plan
The Texas Eastern Products Pipeline
Company, LLC 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”) provides key
employees incentives to achieve improvements in our financial
performance. At December 31, 2008, we had an accrued liability balance of
$0.6 million for compensation related to the 2005 Phantom Unit
Plan. On December 31, 2008, a total of 36,600 phantom units vested
and $0.6 million was paid out to participants in the first quarter of
2009. There were no remaining phantom units outstanding under the 2005
Phantom Unit Plan at March 31, 2009.
EPCO
2006 Long-Term Incentive Plan
The EPCO, Inc. 2006 TPP Long-Term
Incentive Plan (“2006 LTIP”) provides for awards of our Units and other rights
to our non-employee directors and to certain employees of EPCO and its
affiliates providing services to us. Awards granted under the 2006
LTIP may be in the form of restricted units, phantom units, unit options, unit
appreciation rights (“UARs”) and distribution equivalent
rights. Subject to adjustment as provided in the 2006 LTIP, awards
with respect to up to an aggregate of 5,000,000 Units may be granted under the
2006 LTIP. After giving effect to the issuance or forfeiture of restricted
unit awards and option awards through March 31, 2009, a total of 4,388,184
additional Units could be issued under the 2006 LTIP in the future.
Unit
options. The following
table presents unit option activity under the 2006 LTIP for the periods
indicated:
|
Weighted-
|
||||||||||||
|
Weighted-
|
Average
|
|||||||||||
|
Average
|
Remaining
|
|||||||||||
|
Number
|
Strike
Price
|
Contractual
|
||||||||||
|
of
Units
|
(dollars/Unit)
|
Term
(in years)
|
||||||||||
|
Unit
Options:
|
||||||||||||
|
Outstanding
at December 31, 2008
|
355,000 | $ | 40.00 | |||||||||
|
Granted
(1)
|
154,000 | $ | 20.32 | |||||||||
|
Forfeited
|
(47,000 | ) | $ | 40.30 | ||||||||
|
Outstanding
at March 31, 2009 (2)
|
462,000 | $ | 33.41 | 4.80 | ||||||||
|
(1)
The
total grant date fair value of these awards granted on February 23, 2009
was $0.6 million based upon the following assumptions: (i) expected
life of the option of 4.9 years; (ii) risk-free interest rate of 1.8%;
(iii) expected distribution yield on Units of 12.93%; (iv) estimated
forfeiture rate of 17%; and (v) expected unit price volatility on Units of
71.79%.
(2)
No
unit options were exercisable at March 31, 2009.
|
||||||||||||
At March
31, 2009, the estimated total unrecognized compensation cost related to
nonvested unit options granted under the 2006 LTIP was $1.1
million. We expect to recognize this cost over a
weighted average period of 3.43 years in accordance with the
ASA.
9
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Restricted
units. The following
table presents restricted unit activity under the 2006 LTIP for the periods
indicated:
|
Weighted-
|
||||||||
|
Average
Grant
|
||||||||
|
Number
|
Date
Fair Value
|
|||||||
|
of
Units
|
per
Unit (1)
|
|||||||
|
Restricted
Units at December 31, 2008
|
157,300 | |||||||
|
Forfeited
|
(8,100 | ) | $ | 40.31 | ||||
|
Restricted
Units at March 31, 2009
|
149,200 | |||||||
|
(1)
Determined
by dividing the aggregate grant date fair value of awards by the number of
awards issued. The weighted-average grant date fair value per unit
for forfeited awards is determined before an allowance for
forfeitures.
|
||||||||
None of our restricted units vested
during the three months ended March 31, 2009. At March 31, 2009, the
estimated total unrecognized compensation cost related to restricted units
under the 2006 LTIP was $3.3 million. We expect to recognize this cost over
a weighted average period of 2.55 years in accordance with the
ASA.
Phantom
units. At March 31, 2009, a total of 1,647 phantom units were
outstanding, which were awarded in 2007 under the 2006 LTIP to three of the then
non-executive members of the board of directors. Each participant is entitled to
cash distributions equal to the product of the number of phantom units granted
to the participant and the per Unit cash distribution that we paid to our
unitholders. Phantom unit awards to non-executive directors are accounted for in
a manner similar to SFAS 123(R) liability awards.
UARs. At
March 31, 2009, a total of 401,608 UARs were outstanding, which have been
awarded under the 2006 LTIP to non-executive members of the board of directors
and to certain employees providing services directly to us.
|
§
|
Non-Executive
Members of the Board of Directors. At March 31, 2009, a
total of 95,654 UARs, awarded to non-executive members of the board of
directors under the 2006 LTIP, were outstanding at a weighted average
exercise price of $41.82 per Unit (66,225 UARs issued in 2007 at an
exercise price of $45.30 per Unit to the then three non-executive members
of the board of directors and 29,429 UARs issued in 2008 at an exercise
price of $33.98 per Unit to a non-executive member of the board of
directors in connection with his election to the board). UARs
awarded to non-executive directors are accounted for in a manner similar
to SFAS 123(R) liability awards. Mr. Hutchison, who was a
non-executive member of the board of directors at the time of issuance of
these UARs (and the phantom units discussed above), became interim
executive chairman in March 2009.
|
|
§
|
Employees. At
March 31, 2009, a total of 305,954 UARs, awarded under the 2006 LTIP to
certain employees providing services directly to us, were outstanding at
an exercise price of $45.35 per Unit. UARs awarded to employees are
accounted for as liability awards under SFAS 123(R) since the current
intent is to settle the awards in
cash.
|
Employee
Partnerships
In 2008, EPCO formed TEPPCO Unit, L.P.
(“TEPPCO Unit”) and TEPPCO Unit II, L.P. (“TEPPCO Unit II”) (collectively,
“Employee Partnerships”) to serve as long-term incentive arrangements for key
employees of EPCO by providing them with a “profits interest” in the Employee
Partnerships. At March 31, 2009, there was an estimated $1.6 million
and $1.3 million of unrecognized compensation cost related to TEPPCO Unit and
TEPPCO Unit II, respectively. We will recognize our share of these
costs in accordance with the ASA over a weighted average period of 4.52
years.
10
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
In the course of our normal business
operations, we are exposed to certain risks, including changes in interest rates
and commodity prices. In order to manage risks associated with certain
identifiable and anticipated transactions, we use derivative instruments.
Derivatives are financial instruments whose fair value is determined by
changes in a specified benchmark such as interest rates or commodity prices.
Typical derivative instruments include futures, forward contracts, swaps and
other instruments with similar characteristics. Substantially all of
our derivatives are used for non-trading activities.
SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, requires companies to recognize
derivative instruments at fair value as either assets or liabilities on the
balance sheet. While the standard requires that all derivatives be
reported at fair value on the balance sheet, changes in fair value of the
derivative instruments will be reported in different ways depending on the
nature and effectiveness of the hedging activities to which they are
related. After meeting specified conditions, a qualified derivative
may be specifically designated as a total or partial hedge of:
|
§
|
Changes
in the fair value of a recognized asset or liability, or an unrecognized
firm commitment – In a fair value hedge, all gains and losses (of
both the derivative instrument and the hedged item) are recognized in
income during the period of change.
|
|
§
|
Variable
cash flows of a forecasted transaction – In a cash flow hedge, the
effective portion of the hedge is reported in other comprehensive income
and is reclassified into earnings when the forecasted transaction affects
earnings.
|
An effective hedge 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 is the amount by which the derivative instrument exactly offsets the
change in fair value of the hedged item during the reporting
period. Conversely, ineffectiveness represents the change in the fair
value of the derivative instrument that does not exactly offset the change in
the fair value of the hedged item. Any ineffectiveness associated
with a hedge is recognized in earnings immediately. Ineffectiveness
can be caused by, among other things, changes in the timing of forecasted
transactions or a mismatch of terms between the derivative instrument and the
hedged item.
On January 1, 2009, we adopted the
disclosure requirements of SFAS No. 161, Disclosures About Derivative
Financial Instruments and Hedging Activities. SFAS 161
requires enhanced qualitative and quantitative disclosure requirements regarding
derivative instruments. This footnote reflects the new disclosure
standard.
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 debt agreements. This strategy is a
component in controlling our cost of capital associated with such
borrowings. At March 31, 2009, we had no interest rate derivative
instruments outstanding.
At times, we may use treasury lock
derivative instruments to hedge the underlying U.S. treasury rates related to
forecasted issuances of debt. As cash flow hedges, gains or losses on
these instruments are recorded in other comprehensive income and amortized to
earnings using the effective interest method over the estimated term of the
underlying fixed-rate debt. During March 2008, we terminated treasury
locks having a combined notional value of $600.0 million and recognized an
aggregate loss of $23.2 million in other comprehensive income during the first
quarter of 2008. We recognized approximately $3.6 million
of
11
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
this loss
in interest expense during the three months ended March 31, 2008 as a result of
interest payments hedged under the treasury locks not occurring as
forecasted.
For information regarding fair value
amounts and gains and losses on interest rate derivative instruments and related
hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains and
Losses on Derivative Instruments and Related Hedged Items” within this Note
4.
Commodity
Derivative Instruments
We seek to maintain a position that is
substantially balanced between crude oil purchases and related sales and future
delivery obligations. The price of crude oil is subject to
fluctuations in response to changes in supply, demand, general market
uncertainty and a variety of additional factors that are beyond our
control. In order to manage the price risk associated with crude oil, we
enter into commodity derivative instruments such as forwards, basis swaps and
futures contracts. The purpose of such hedging strategy is to either
balance our inventory position or to lock in a profit margin.
At March 31, 2009, we had no
outstanding commodity derivatives designated as hedging instruments under SFAS
133. Currently, our commodity derivative instruments do not meet the
hedge accounting requirements of SFAS 133 and are accounted for as economic
hedges using mark-to-market accounting. These financial instruments
had a minimal impact on our earnings. The following table summarizes
our outstanding commodity derivative instruments not designated as hedging
instruments under SFAS 133 at March 31, 2009:
|
Accounting
|
||
|
Derivative
Purpose
|
Volume
(1)
|
Treatment
|
|
Derivatives
not designated as hedging instruments under SFAS 133:
|
||
|
Crude
oil risk management activities (2)
|
2.8
MMBbls
|
Mark-to-market
|
|
(1)
Volumes
for derivatives not designated as hedging instruments reflect the absolute
value of the derivative notional volumes.
(2) Reflects
the use of derivative instruments to manage risks associated with our
portfolio of crude oil storage assets. These commodity
derivative instruments have forward positions through June
2009.
|
||
For information regarding fair value
amounts and gains and losses on commodity derivative instruments and
related hedged items, see “Tabular Presentation of Fair Value Amounts, and Gains
and Losses on Derivative Instruments and Related Hedged Items” within this Note
4.
Tabular Presentation of Fair Value
Amounts, and Gains and Losses on
Derivative
Instruments and Related Hedged Items
The
following table provides a balance sheet overview of our derivative assets and
liabilities at the dates indicated:
|
Asset
Derivatives
|
Liability
Derivatives
|
|||||||||||||||||||
|
March
31, 2009
|
December
31, 2008
|
March
31, 2009
|
December
31, 2008
|
|||||||||||||||||
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
|||||||||||||
|
Location
|
Value
|
Location
|
Value
|
Location
|
Value
|
Location
|
Value
|
|||||||||||||
|
Derivatives
not designated as hedging instruments under SFAS
133
|
||||||||||||||||||||
|
Commodity
derivatives
|
Other
current
assets
|
$ | 1.8 |
Other
current
assets
|
$ | 15.7 |
Other
current liabilities
|
$ | 1.1 |
Other
current liabilities
|
$ | 15.7 | ||||||||
|
Total
derivatives not
|
||||||||||||||||||||
|
designated
as hedging
|
||||||||||||||||||||
|
instruments
|
$ | 1.8 | $ | 15.7 | $ | 1.1 | $ | 15.7 | ||||||||||||
12
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
following table presents the effect of our derivative instruments designated as
fair value hedges under SFAS 133 on our condensed consolidated statements of
income for the periods indicated:
|
Derivatives
in SFAS 133
|
Gain/(Loss)
Recognized in
|
Gain/(Loss)
Recognized in
|
|||||||||
|
Fair
Value
|
Income
on Derivative
|
Income
on Hedged Item
|
|||||||||
|
Hedging
Relationships
|
Amount
|
Location
|
Amount
|
Location
|
|||||||
|
For
the Three Months
|
For
the Three Months
|
||||||||||
|
Ended
March 31,
|
Ended
March 31,
|
||||||||||
|
2009
|
2008
|
2009
|
2008
|
||||||||
|
Interest
rate derivatives
|
$ |
--
|
$ --
|
Interest expense
|
$ |
--
|
$ (1.0)
|
Interest expense
|
|||
|
Total
|
$ |
--
|
$ --
|
$ |
--
|
$
(1.0)
|
|||||
The
following tables present the effect of our derivative instruments designated as
cash flow hedges under SFAS 133 on our condensed consolidated statements of
income for the periods indicated:
|
Change
in Value
|
|||||
|
Derivatives
|
Recognized
in OCI on
|
||||
|
in
SFAS 133 Cash Flow
|
Derivative
|
||||
|
Hedging
Relationships
|
(Effective
Portion)
|
||||
|
For
the Three Months
|
|||||
|
Ended
March 31,
|
|||||
|
2009
|
2008
|
||||
|
Interest
rate derivatives
|
$ |
--
|
$ (23.2)
|
||
|
Commodity
derivatives
|
--
|
(6.5)
|
|||
|
Total
|
$ |
--
|
$ (29.7)
|
||
|
Amount
of Gain/(Loss)
|
|||||||||
|
Derivatives
|
Location
of Gain/(Loss)
|
Reclassified
from AOCI
|
|||||||
|
in
SFAS 133 Cash Flow
|
Reclassified
from AOCI
|
to
Income
|
|||||||
|
Hedging
Relationships
|
into
Income (Effective Portion)
|
(Effective
Portion)
|
|||||||
|
For
the Three Months
|
|||||||||
|
Ended
March 31,
|
|||||||||
|
2009
|
2008
|
||||||||
|
Interest
rate derivatives
|
Interest
expense
|
$ | (1.4 | ) | $ | -- | |||
|
Commodity
derivatives
|
Revenue
|
-- | (9.6 | ) | |||||
|
Total
|
$ | (1.4 | ) | $ | (9.6 | ) | |||
|
Location
of Gain/(Loss)
|
Amount
of Gain/(Loss)
|
||||||||
|
Derivatives
|
Recognized
in Income
|
Recognized
in Income on
|
|||||||
|
in
SFAS 133 Cash Flow
|
on
Ineffective Portion
|
Ineffective
Portion of
|
|||||||
|
Hedging
Relationships
|
of
Derivative
|
Derivative
|
|||||||
|
For
the Three Months
|
|||||||||
|
Ended
March 31,
|
|||||||||
|
2009
|
2008
|
||||||||
|
Interest
rate derivatives
|
Interest
expense
|
$ | -- | $ | (3.6 | ) | |||
|
Commodity
derivatives
|
Revenue
|
-- | -- | ||||||
|
Total
|
$ | -- | $ | (3.6 | ) | ||||
Over the
next twelve months, we expect to reclassify $5.9 million of accumulated other
comprehensive loss attributable to settled treasury locks to earnings as an
increase to interest expense.
13
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
following table presents the effect of our derivative instruments not designated
as hedging instruments under SFAS 133 on our condensed consolidated statements
of income for the periods indicated:
|
Derivatives
Not
|
Gain/(Loss)
Recognized in
|
|||||
|
Designated
as SFAS 133
|
Income
on Derivative
|
|||||
|
Hedging
Instruments
|
Amount
|
Location
|
||||
|
For
the Three Months
|
||||||
|
Ended
March 31,
|
||||||
|
2009
|
2008
|
|||||
|
Commodity
derivatives
|
$ |
0.8
|
$ 0.4
|
Revenue
|
||
|
Total
|
$ |
0.8
|
$ 0.4
|
|||
Credit-Risk Related Contingent Features
in Derivative Instruments
We have no credit-risk related
contingent features in any of our derivative
instruments.
SFAS
157 – Fair Value Measurements
SFAS 157
defines fair value 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. The following table sets forth, by level
within the fair value hierarchy, our financial assets and liabilities measured
on a recurring basis at March 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
and their placement within the fair value hierarchy levels.
|
Level
2
|
Level
3
|
Total
|
||||||||||
|
Financial
assets:
|
||||||||||||
|
Commodity
derivative instruments
|
$ | 1.4 | $ | 0.4 | $ | 1.8 | ||||||
|
Total
|
$ | 1.4 | $ | 0.4 | $ | 1.8 | ||||||
|
Financial
liabilities:
|
||||||||||||
|
Commodity
derivative instruments
|
$ | 1.1 | $ | -- | $ | 1.1 | ||||||
|
Total
|
$ | 1.1 | $ | -- | $ | 1.1 | ||||||
The
following table sets forth a reconciliation of changes in the fair value of our
Level 3 financial assets and liabilities for the periods indicated:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Balance,
January 1
|
$ | (0.1 | ) | $ | (0.4 | ) | ||
|
Total
gains included in net income
|
0.4 | 0.4 | ||||||
|
Purchases,
issuances, settlements
|
0.1 | -- | ||||||
|
Balance,
March 31
|
$ | 0.4 | $ | -- | ||||
We adopted the provisions of SFAS 157
that apply to nonfinancial assets and liabilities on January 1,
2009. Our adoption of this guidance had no impact on our financial
position, results of operations or cash flows.
14
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Inventories are valued at the lower of
cost (based on weighted average cost method) or market. The major
components of inventories were as follows at the dates indicated:
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Crude
oil (1)
|
$ | 21.5 | $ | 32.8 | ||||
|
Refined
products and LPGs (2)
|
10.2 | 0.4 | ||||||
|
Lubrication
oils and specialty chemicals
|
11.2 | 11.1 | ||||||
|
Materials
and supplies
|
9.1 | 8.6 | ||||||
|
NGLs
|
0.6 | -- | ||||||
|
Total
|
$ | 52.6 | $ | 52.9 | ||||
|
(1)
At
March 31, 2009 and December 31, 2008, $21.2 million and $30.7 million,
respectively, of our crude oil inventory was subject to forward sales
contracts.
(2)
Refined
products and LPGs inventory is managed on a combined
basis.
|
||||||||
Due to fluctuating commodity prices, we
recognize lower of cost or market (“LCM”) adjustments when the carrying value of
our inventories exceeds their net realizable value. These non-cash
charges are a component of costs and expenses in the period they are recognized.
For the three months ended March 31, 2009 and 2008, we recognized LCM
adjustments of approximately $1.0 million and less than $0.1 million,
respectively.
Our property, plant and equipment
values and accumulated depreciation balances were as follows at the dates
indicated:
|
Estimated
|
||||||||||||
|
Useful
Life
|
March
31,
|
December
31,
|
||||||||||
|
in
Years
|
2009
|
2008
|
||||||||||
|
Plants
and pipelines (1)
|
5-40(4)
|
$ | 1,926.9 | $ | 1,919.7 | |||||||
|
Underground
and other storage facilities (2)
|
5-40(5)
|
306.4 | 296.8 | |||||||||
|
Transportation
equipment (3)
|
5-10
|
|
11.9 | 11.3 | ||||||||
|
Marine
vessels
|
20-30
|
453.0 | 453.0 | |||||||||
|
Land
and right of way
|
143.9 | 143.8 | ||||||||||
|
Construction
work in progress
|
378.9 | 294.1 | ||||||||||
|
Total
property, plant and equipment
|
$ | 3,221.0 | $ | 3,118.7 | ||||||||
|
Less:
accumulated depreciation
|
703.8 | 678.8 | ||||||||||
|
Property,
plant and equipment, net
|
$ | 2,517.2 | $ | 2,439.9 | ||||||||
|
(1) Plants
and pipelines include refined products, LPGs, NGLs, 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,
storage tanks and other related assets.
(3)
Transportation
equipment includes vehicles and similar assets used in our
operations.
(4)
The
estimated useful lives of major components of this category are as
follows: pipelines, 20-40 years (with some equipment at 5 years);
terminal facilities, 10-40 years; office furniture and equipment, 5-10
years; buildings, 20-40 years; and laboratory and shop equipment, 5-40
years.
(5)
The
estimated useful lives of major components of this category are as
follows: underground storage facilities, 20-40 years (with some
components at 5 years); and storage tanks, 20-30 years.
|
||||||||||||
15
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
following table summarizes our depreciation expense and capitalized interest
amounts for the periods indicated:
|
For
the Three Months
|
|||||
|
Ended
March 31,
|
|||||
|
2009
|
2008
|
||||
|
Depreciation
expense (1)
|
$ 25.3
|
$ 21.9
|
|||
|
Capitalized
interest (2)
|
5.3
|
4.4
|
|||
|
(1)
Depreciation
expense is a component of depreciation and amortization expense as
presented in our statements of consolidated income.
(2)
Capitalized
interest (included in interest expense on our statements of consolidated
income) increases the carrying value of the associated asset and reduces
interest expense during the period it is
recorded.
|
|||||
Asset
Retirement Obligations
Asset retirement obligations (“AROs”)
are legal obligations associated with the retirement of certain tangible
long-lived assets that result from acquisitions, construction, development
and/or normal operations or a combination of these factors. Our ARO
liability balance at March 31, 2009 and December 31, 2008 was $1.5
million. Accretion expense was less than $0.1 million for the three
months ended March 31, 2009. Property, plant and equipment at March
31, 2009 includes $0.7 million of asset retirement costs capitalized as an
increase in the associated long-lived asset.
We own interests in related businesses
that are accounted for using the equity method of accounting. These
investments are identified below by reporting business segment (see Note 11 for
a general discussion of our business segments). The following table
presents our investments in unconsolidated affiliates at the dates
indicated:
|
Ownership
|
||||||||||||
|
Percentage
at
|
||||||||||||
|
March
31,
|
March
31,
|
December
31,
|
||||||||||
|
2009
|
2009
|
2008
|
||||||||||
|
Downstream
Segment:
|
||||||||||||
|
Centennial
Pipeline LLC (“Centennial”)
|
50.0%
|
$ | 70.2 | $ | 71.8 | |||||||
|
Other
|
25.0%
|
0.4 | 0.4 | |||||||||
|
Upstream
Segment:
|
||||||||||||
|
Seaway
Crude Pipeline Company (“Seaway”)
|
50.0%
|
184.1 | 190.1 | |||||||||
|
Texas
Offshore Port System (1)
|
33.3%
|
34.2 | 35.9 | |||||||||
|
Midstream
Segment:
|
||||||||||||
|
Jonah
Gas Gathering Company (“Jonah”)
|
80.64%
|
955.9 | 957.7 | |||||||||
|
Total
|
$ | 1,244.8 | $ | 1,255.9 | ||||||||
|
(1)
In
January 2009, we received a $3.1 million refund of our 2008 contributions
to Texas Offshore Port System due to a delay in the timing of the expected
project spending. In February and March 2009, we then invested an
additional $1.4 million in Texas Offshore Port System. See Note 17
for information regarding our dissociation with this
partnership.
|
||||||||||||
Our
investments in Centennial, Seaway and Jonah included excess cost amounts
totaling $73.1 million and $72.9 million at March 31, 2009 and December 31,
2008, respectively. The value assigned to our excess investment in
Centennial was created upon its formation, the value assigned to our excess
investment in Seaway was created upon acquisition of our ownership interest in
Seaway, and the value assigned to our excess investment in Jonah was created as
a result of interest capitalized on the construction of Jonah’s
expansion. We amortize such excess cost as a reduction in equity in
earnings of unconsolidated
16
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
affiliates in a manner
similar to depreciation over the life of applicable contracts or assets acquired
or constructed. Amortization of such excess cost amounts was $1.5
million and $1.1 million for the three months ended March 31, 2009 and
2008, respectively. For the remainder of 2009, amortization expense
associated with our excess investments is currently estimated at $4.2
million.
The following table
summarizes equity in earnings (losses) of unconsolidated affiliates by business
segment for the periods indicated:
|
For
the Three Months
|
|||||
|
Ended
March 31,
|
|||||
|
2009
|
2008
|
||||
|
Downstream
Segment
|
$ (3.1)
|
$ (4.1)
|
|||
|
Upstream
Segment
|
3.3
|
3.0
|
|||
|
Midstream
Segment
|
25.6
|
23.7
|
|||
|
Intersegment
eliminations
|
(0.7)
|
(2.9) | |||
|
Total
|
$ 25.1
|
$ 19.7 | |||
On a quarterly basis, we monitor the
underlying business fundamentals of our investments in unconsolidated affiliates
and test such investments for impairment when impairment indicators are
present. As a result of our reviews for the first quarter of 2009, no
impairment charges were required. We have the intent and ability to
hold these investments, which are integral to our operations.
Summarized
Financial Information of Unconsolidated Affiliates
Summarized combined income statement
data by reporting segment for the periods indicated is
presented below (on a 100% basis):
|
Summarized
Income Statement Information For the Three Months Ended
|
||||||||||||||||||||||||
|
March
31, 2009
|
March
31, 2008
|
|||||||||||||||||||||||
|
Operating
|
Net
|
Operating
|
Net
|
|||||||||||||||||||||
|
Revenues
|
Income
|
Income
(Loss)
|
Revenues
|
Income
|
Income
(Loss)
|
|||||||||||||||||||
|
Downstream
Segment
|
$ | 9.7 | $ | 2.2 | $ | (0.5 | ) | $ | 9.6 | $ | 0.9 | $ | (1.8 | ) | ||||||||||
|
Upstream
Segment
|
19.7 | 8.7 | 8.7 | 20.6 | 10.4 | 10.4 | ||||||||||||||||||
|
Midstream
Segment
|
59.4 | 31.9 | 32.0 | 58.2 | 29.3 | 29.4 | ||||||||||||||||||
Intangible
Assets
The following table summarizes
intangible assets by business segment being amortized at the dates
indicated:
|
March
31, 2009
|
December
31, 2008
|
|||||||||||||||||||||||
|
Gross
|
Accum.
|
Carrying
|
Gross
|
Accum.
|
Carrying
|
|||||||||||||||||||
|
Value
|
Amort.
|
Value
|
Value
|
Amort.
|
Value
|
|||||||||||||||||||
|
Downstream
Segment
|
$ | 8.0 | $ | (1.3 | ) | $ | 6.7 | $ | 6.6 | $ | (1.2 | ) | $ | 5.4 | ||||||||||
|
Upstream
Segment
|
11.5 | (3.5 | ) | 8.0 | 11.5 | (3.4 | ) | 8.1 | ||||||||||||||||
|
Midstream
Segment
|
277.9 | (150.8 | ) | 127.1 | 277.9 | (146.3 | ) | 131.6 | ||||||||||||||||
|
Marine
Services Segment
|
70.0 | (9.5 | ) | 60.5 | 70.0 | (7.4 | ) | 62.6 | ||||||||||||||||
|
Total
|
$ | 367.4 | $ | (165.1 | ) | $ | 202.3 | $ | 366.0 | $ | (158.3 | ) | $ | 207.7 | ||||||||||
17
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
following table presents amortization expense of intangible assets by business
segment for the periods indicated:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Downstream
Segment
|
$ | 0.1 | $ | 0.1 | ||||
|
Upstream
Segment
|
0.1 | 0.1 | ||||||
|
Midstream
Segment
|
4.5 | 5.0 | ||||||
|
Marine
Services Segment
|
2.1 | 1.2 | ||||||
|
Total
|
$ | 6.8 | $ | 6.4 | ||||
For the
remainder of 2009, amortization expense associated with our intangible assets is
currently estimated at $19.7 million.
Goodwill
The following table presents the
carrying amount of goodwill by business segment at the dates
indicated:
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Downstream
Segment
|
$ | 1.3 | $ | 1.3 | ||||
|
Upstream
Segment
|
14.9 | 14.9 | ||||||
|
Marine
Services Segment
|
90.4 | 90.4 | ||||||
|
Total
|
$ | 106.6 | $ | 106.6 | ||||
The
following table summarizes the principal amounts outstanding under all of our
debt instruments at the dates indicated:
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Senior
debt obligations: (1)
|
||||||||
|
Revolving Credit Facility, due December 2012 (2)
|
$ | 565.6 | $ | 516.7 | ||||
|
7.625% Senior Notes, due February 2012
|
500.0 | 500.0 | ||||||
|
6.125% Senior Notes, due February 2013
|
200.0 | 200.0 | ||||||
|
5.90% Senior Notes, due April 2013
|
250.0 | 250.0 | ||||||
|
6.65% Senior Notes, due April 2018
|
350.0 | 350.0 | ||||||
|
7.55% Senior Notes, due April 2038
|
400.0 | 400.0 | ||||||
|
Total principal amount of long-term senior debt
obligations
|
2,265.6 | 2,216.7 | ||||||
|
7.000% Junior Subordinated Notes, due June 2067 (1)
|
300.0 | 300.0 | ||||||
|
Total principal amount of long-term debt obligations
|
2,565.6 | 2,516.7 | ||||||
|
Adjustment to carrying value associated with hedges of fair value
and
|
||||||||
|
unamortized discounts (3)
|
11.7 | 12.9 | ||||||
|
Total long-term debt obligations
|
2,577.3 | 2,529.6 | ||||||
|
Total
Debt Instruments (3)
|
$ | 2,577.3 | $ | 2,529.6 | ||||
|
(1)
TE
Products, TCTM, TEPPCO Midstream and Val Verde Gas Gathering Company, L.P.
(“Val Verde”) (collectively, the “Guarantor Subsidiaries”) have issued
full, unconditional, joint and several guarantees of our senior notes,
junior subordinated notes and revolving credit facility (“Revolving Credit
Facility”).
(2) The
weighted average interest rate paid on our variable rate Revolving Credit
Facility at March 31, 2009 was 1.13%.
(3)
From
time to time we enter into interest rate swap agreements to hedge our
exposure to changes in the fair value on a portion of the debt obligations
presented above (see Note 4). At March 31, 2009 and December 31,
2008, amount includes $5.1 million and $5.2 million of unamortized
discounts, respectively, and $16.8 million and $18.1 million,
respectively, related to fair value hedges.
|
||||||||
18
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Except for
routine fluctuations in our unsecured Revolving Credit Facility, there have been
no material changes in the terms of our debt obligations since those
reported in our Annual Report on Form 10-K for the year ended December 31,
2008.
During
September 2008, Lehman Brothers Bank, FSB (“Lehman”), which had a 4.05%
participation in our Revolving Credit Facility, stopped funding its commitment
following the bankruptcy filing of its parent. Assuming that future
fundings are not received for the Lehman percentage commitment, aggregate
available capacity would be reduced by approximately $28.9 million. At
March 31, 2009, our available borrowing capacity under the Revolving
Credit Facility was approximately $355.5 million.
Covenants
We were in compliance with the
covenants of our long-term debt obligations at March 31, 2009.
Debt
Obligations of Unconsolidated Affiliates
We have one unconsolidated affiliate,
Centennial, with long-term debt obligations. The following table
shows the total debt of Centennial at March 31, 2009 (on a 100% basis) and the
corresponding scheduled maturities of such debt.
|
Our
|
Scheduled
Maturities of Debt
|
|||||||||||||||||||||||||||||||
|
Ownership
|
After
|
|||||||||||||||||||||||||||||||
|
Interest
|
Total
|
2009
|
2010
|
2011
|
2012
|
2013
|
2013
|
|||||||||||||||||||||||||
|
Centennial
|
50% | $ | 127.4 | $ | 7.4 | $ | 9.1 | $ | 9.0 | $ | 8.9 | $ | 8.6 | $ | 84.4 | |||||||||||||||||
At March
31, 2009 and December 31, 2008, Centennial’s debt obligations consisted of
$127.4 million and $129.9 million, respectively, borrowed under a master shelf
loan agreement. 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 (see Note 14).
There
have been no material changes in the terms of the debt obligations of Centennial
since those reported in our Annual Report on Form 10-K for the year ended
December 31, 2008.
Our Units represent limited partner
interests, which give the holders thereof the right to participate in
distributions and to exercise the other rights or privileges available to them
under our Partnership Agreement. We are managed by our General
Partner.
In accordance with the Partnership
Agreement, capital accounts are maintained for our General Partner and limited
partners. The capital account provisions of our Partnership Agreement
incorporate principles established for U.S. federal income tax purposes and
are not comparable to the equity accounts reflected under GAAP in our
consolidated financial statements. In connection with the amendment of our
Partnership Agreement in December 2006, the General Partner’s obligation to make
capital contributions to maintain its 2% capital account was
eliminated.
Our Partnership Agreement sets forth
the calculation to be used in determining the amount and priority of cash
distributions that our limited partners and General Partner will
receive. Net income reflected under GAAP in our financial statements is
allocated between the General Partner and the limited partners in the same
proportion as aggregate cash distributions made to the General Partner and the
limited partners during the period. Net income determined under our
Partnership Agreement, however,
19
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
incorporates
principles established for U.S. federal income tax purposes and is not
comparable to net income reflected under GAAP in our financial
statements.
Registration
Statements
In general, the Partnership Agreement
authorizes us to issue an unlimited number of additional limited partner
interests and other equity securities for such consideration and on such terms
and conditions as may be established by our General Partner in its sole
discretion (subject, under certain circumstances, to the approval of our
unitholders).
We have a universal shelf registration
statement on file with the SEC that allows us to issue an unlimited amount of
debt and equity securities.
We also
have a registration statement on file with the SEC authorizing the issuance of
up to 10,000,000 Units in connection with our distribution reinvestment plan
(“DRIP”). A total of 481,281 Units have been issued under this
registration statement from inception of the DRIP through March 31,
2009.
In
addition, we have a registration statement on file related to our employee unit
purchase plan (“EUPP”), under which we can issue up to 1,000,000
Units. A total of 35,111 Units have been issued to employees
under this plan from inception of the EUPP through March 31, 2009.
During the three months ended March 31,
2009, a total of 70,555 Units were issued in connection with the DRIP and the
EUPP. Total net proceeds received during the three months ended March
31, 2009 from these Unit offerings was $1.6 million.
Quarterly
Distributions of Available Cash
We make quarterly cash distributions of
all of our available cash, generally defined in our Partnership Agreement as
consolidated cash receipts less consolidated cash disbursements and cash
reserves established by the General Partner in its reasonable discretion
(“Available Cash”). Pursuant to the Partnership Agreement, the
General Partner receives incremental incentive cash distributions when
unitholders’ cash distributions exceed certain target thresholds.
The
following table reflects the allocation of total distributions paid during the
periods indicated:
|
For
the Three Months
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Limited
Partner Units
|
$ | 76.0 | $ | 62.5 | ||||
|
General
Partner Ownership Interest
|
1.5 | 1.3 | ||||||
|
General
Partner Incentive
|
13.9 | 11.1 | ||||||
|
Total
Cash Distributions Paid
|
$ | 91.4 | $ | 74.9 | ||||
|
Total
Cash Distributions Paid Per Unit
|
$ | 0.725 | $ | 0.695 | ||||
Our
quarterly cash distributions for 2009 are presented in the following
table:
|
Distribution
|
Record
|
Payment
|
|||||
|
per
Unit
|
Date
|
Date
|
|||||
|
1st
Quarter 2009 (1)
|
$ | 0.725 |
Apr.
30, 2009
|
May
7, 2009
|
|||
|
(1)
The
first quarter 2009 cash distribution totaled approximately $91.4
million.
|
|||||||
20
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Summary
of Changes in Outstanding Units
The
following table summarizes changes in our outstanding units since December
31, 2008:
|
Limited
|
||||||||||||
|
Partner
|
Restricted
|
|||||||||||
|
Units
|
Units
|
Total
|
||||||||||
|
Balance,
December 31, 2008
|
104,547,561 | 157,300 | 104,704,861 | |||||||||
|
Units issued in connection with DRIP
|
63,048 | -- | 63,048 | |||||||||
|
Units issued in connection with EUPP
|
7,507 | -- | 7,507 | |||||||||
|
Forfeiture of restricted units
|
-- | (8,100 | ) | (8,100 | ) | |||||||
|
Balance,
March 31, 2009
|
104,618,116 | 149,200 | 104,767,316 | |||||||||
General
Partner’s Interest
At March 31, 2009 and December 31,
2008, we had deficit balances of $112.5 million and $110.3 million,
respectively, in our General Partner’s equity account. These negative balances
do not represent assets to us and do not represent obligations of the General
Partner to contribute cash or other property to us. According to the
Partnership Agreement, in the event of our dissolution, after satisfying our
liabilities, our remaining assets would be divided among our limited partners
and the General Partner generally in the same proportion as Available Cash but
calculated on a cumulative basis over the life of the Partnership. If
a deficit balance still remains in the General Partner’s equity account after
all allocations are made between the partners, the General Partner would not be
required to make whole any such deficit.
Accumulated
Other Comprehensive Income (Loss)
Our accumulated other comprehensive
loss balance consisted of losses of $44.4 million and $45.8 million related to
interest rate and treasury lock derivative instruments at March 31, 2009 and
December 31, 2008, respectively.
We have four reporting
segments:
|
§
|
Our
Downstream Segment, which is engaged in the pipeline transportation,
marketing and storage of refined products, LPGs and
petrochemicals;
|
|
§
|
Our
Upstream Segment, which is engaged in the gathering, pipeline
transportation, marketing and storage of crude oil, distribution of
lubrication oils and specialty chemicals and fuel transportation
services;
|
|
§
|
Our
Midstream Segment, which is engaged in the gathering of natural gas,
fractionation of NGLs and pipeline transportation of NGLs;
and
|
|
§
|
Our
Marine Services Segment, which is engaged in the marine transportation of
refined products, crude oil, condensate, asphalt, heavy fuel oil and other
heated oil products via tow boats and tank
barges.
|
21
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents our
measurement of earnings before interest expense for the periods
indicated:
|
For
the Three Months
|
|||||
|
Ended
March 31,
|
|||||
|
2009
|
2008
|
||||
|
Total
operating revenues
|
$ 1,457.6
|
$
2,808.5
|
|||
|
Less: Total
costs and expenses
|
1,371.9
|
2,725.0 | |||
|
Operating income
|
85.7
|
83.5
|
|||
|
Add: Equity
in earnings of unconsolidated affiliates
|
25.1
|
19.7
|
|||
|
Other,
net
|
0.3
|
0.3 | |||
|
Earnings
before interest expense and provision for income taxes
|
$ 111.1
|
$ 103.5 | |||
A
reconciliation of our earnings before interest expense and provision for income
taxes to net income for the periods indicated is as follows:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Earnings
before interest expense and provision for income taxes
|
$ | 111.1 | $ | 103.5 | ||||
|
Interest
expense
|
(32.1 | ) | (38.6 | ) | ||||
|
Income
before provision for income taxes
|
79.0 | 64.9 | ||||||
|
Provision
for income taxes
|
0.8 | 0.8 | ||||||
|
Net
income
|
$ | 78.2 | $ | 64.1 | ||||
The amounts indicated below as
“Partnership and Other” for income and expense items (including operating
income) relate primarily to intersegment eliminations from activities among our
reporting segments. Amounts indicated below as “Partnership and
Other” for assets and capital expenditures include the elimination of
intersegment related party receivables and investment balances among our
reporting segments and assets that we hold that have not been allocated to any
of our reporting segments (including such items as corporate furniture and
fixtures, vehicles, computer hardware and software, prepaid insurance and
unamortized debt issuance costs on debt issued at the Partnership
level).
22
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The table
below includes information by segment, together with reconciliations to our
consolidated totals, for the periods indicated:
|
Reportable
Segments
|
||||||||||||||||||||||||
|
Marine
|
||||||||||||||||||||||||
|
Downstream
|
Upstream
|
Midstream
|
Services
|
Partnership
|
||||||||||||||||||||
|
Segment
|
Segment
|
Segment
|
Segment
|
and
Other
|
Consolidated
|
|||||||||||||||||||
|
Revenues
from third parties:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
$ | 76.6 | $ | 1,296.1 | $ | 25.2 | $ | 36.9 | $ | -- | $ | 1,434.8 | ||||||||||||
|
Three
months ended March 31, 2008
|
94.5 | 2,655.1 | 26.6 | 25.5 | -- | 2,801.7 | ||||||||||||||||||
|
Revenues
from related parties:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
18.9 | 0.1 | 3.8 | -- | -- | 22.8 | ||||||||||||||||||
|
Three
months ended March 31, 2008
|
3.1 | 0.2 | 3.5 | -- | (0.1 | ) | 6.7 | |||||||||||||||||
|
Total
revenues:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
95.5 | 1,296.2 | 29.0 | 36.9 | -- | 1,457.6 | ||||||||||||||||||
|
Three
months ended March 31, 2008
|
97.7 | 2,655.3 | 30.1 | 25.5 | (0.1 | ) | 2,808.5 | |||||||||||||||||
|
Depreciation
and amortization:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
11.5 | 5.6 | 9.5 | 6.4 | -- | 33.0 | ||||||||||||||||||
|
Three
months ended March 31, 2008
|
10.2 | 4.8 | 9.6 | 3.7 | -- | 28.3 | ||||||||||||||||||
|
Operating
income:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
34.4 | 40.9 | 4.5 | 5.2 | 0.7 | 85.7 | ||||||||||||||||||
|
Three
months ended March 31, 2008
|
36.3 | 29.3 | 8.4 | 6.6 | 2.9 | 83.5 | ||||||||||||||||||
|
Equity
in earnings (losses) of unconsolidated
affiliates:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
(3.1 | ) | 3.3 | 25.6 | -- | (0.7 | ) | 25.1 | ||||||||||||||||
|
Three
months ended March 31, 2008
|
(4.1 | ) | 3.0 | 23.7 | -- | (2.9 | ) | 19.7 | ||||||||||||||||
|
Earnings
before interest expense and provision
|
||||||||||||||||||||||||
|
for
income taxes:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
31.6 | 44.2 | 30.1 | 5.2 | -- | 111.1 | ||||||||||||||||||
|
Three
months ended March 31, 2008
|
32.4 | 32.3 | 32.2 | 6.6 | -- | 103.5 | ||||||||||||||||||
|
Capital
expenditures:
|
||||||||||||||||||||||||
|
Three
months ended March 31, 2009
|
78.1 | 11.4 | 4.2 | 7.2 | 0.7 | 101.6 | ||||||||||||||||||
|
Year
ended December 31, 2008
|
209.8 | 33.4 | 5.2 | 43.6 | 8.5 | 300.5 | ||||||||||||||||||
|
Segment
assets:
|
||||||||||||||||||||||||
|
At
March 31, 2009
|
1,387.9 | 1,482.1 | 1,536.0 | 647.9 | (11.2 | ) | 5,042.7 | |||||||||||||||||
|
At
December 31, 2008
|
1,320.9 | 1,586.3 | 1,529.1 | 653.3 | (39.8 | ) | 5,049.8 | |||||||||||||||||
|
Investments
in unconsolidated affiliates:
|
||||||||||||||||||||||||
|
At
March 31, 2009
|
61.8 | 218.3 | 955.9 | -- | 8.8 | 1,244.8 | ||||||||||||||||||
|
At
December 31, 2008
|
63.2 | 226.0 | 957.7 | -- | 9.0 | 1,255.9 | ||||||||||||||||||
|
Intangible
assets, net:
|
||||||||||||||||||||||||
|
At
March 31, 2009
|
6.7 | 8.0 | 127.1 | 60.5 | -- | 202.3 | ||||||||||||||||||
|
At
December 31, 2008
|
5.4 | 8.1 | 131.6 | 62.6 | -- | 207.7 | ||||||||||||||||||
|
Goodwill:
|
||||||||||||||||||||||||
|
At
March 31, 2009
|
1.3 | 14.9 | -- | 90.4 | -- | 106.6 | ||||||||||||||||||
|
At
December 31, 2008
|
1.3 | 14.9 | -- | 90.4 | -- | 106.6 | ||||||||||||||||||
23
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes related
party transactions for the periods indicated:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Revenues
from EPCO and affiliates:
|
||||||||
|
Sales of petroleum products (1)
|
$ | 0.1 | $ | 0.6 | ||||
|
Transportation – NGLs (2)
|
3.8 | 3.4 | ||||||
|
Transportation – LPGs (3)
|
4.9 | 2.3 | ||||||
|
Other operating revenues (4)
|
14.0 | 0.4 | ||||||
|
Related party
revenues
|
$ | 22.8 | $ | 6.7 | ||||
|
Costs
and Expenses from EPCO and affiliates:
|
||||||||
|
Purchases of petroleum products (5)
|
$ | 26.7 | $ | 19.7 | ||||
|
Operating expense (6)
|
28.6 | 26.1 | ||||||
|
General and administrative (7)
|
8.1 | 8.5 | ||||||
|
Costs
and Expenses from unconsolidated affiliates:
|
||||||||
|
Purchases of petroleum products (8)
|
(0.7 | ) | 1.6 | |||||
|
Operating expense (9)
|
1.6 | 2.3 | ||||||
|
Costs
and Expenses from Cenac and affiliates:
|
||||||||
|
Operating expense (10)
|
13.4 | 7.4 | ||||||
|
General and administrative (11)
|
1.1 | 0.5 | ||||||
|
Related party costs and
expenses
|
$ | 78.8 | $ | 66.1 | ||||
|
(1)
Includes
sales from Lubrication Services, LLC (“LSI”) to Enterprise Products
Partners and certain of its subsidiaries.
(2)
Includes
revenues from NGL transportation on the Chaparral Pipeline Company, LLC
and Quanah Pipeline Company, LLC (collectively referred to as “Chaparral”
or “Chaparral NGL system”) and Panola Pipeline Company, LLC (“Panola
Pipeline") NGL pipelines from Enterprise Products Partners and certain of
its subsidiaries.
(3)
Includes
revenues from LPG transportation on the TE Products pipeline from
Enterprise Products Partners and certain of its
subsidiaries.
(4)
Includes
sales of product inventory from TE Products to Enterprise Products
Partners and other operating revenues on the TE Products pipeline from
Enterprise Products Partners and certain of its subsidiaries.
(5)
Includes
TEPPCO Crude Oil, LLC (“TCO”) purchases of petroleum products of $20.6
million and $15.6 million for the three months ended March 31, 2009 and
2008, respectively, from Enterprise Products Partners and certain of its
subsidiaries.
(6)
Includes
operating payroll, payroll related expenses and other operating expenses,
including reimbursements related to employee benefits and employee benefit
plans, incurred by EPCO in managing us and our subsidiaries in accordance
with the ASA and expenses related to Chaparral’s use of transportation
services of a subsidiary of Enterprise Products Partners. Also
includes insurance expense for the three months ended March 31, 2009 and
2008, respectively, of $3.2 million and $2.9 million, related to premiums
paid by EPCO on our behalf. The majority of our insurance coverage,
including property, liability, business interruption, auto and directors’
and officers’ liability insurance, is obtained through EPCO.
(7)
Includes
administrative payroll, payroll related expenses and other administrative
expenses, including reimbursements related to employee benefits and
employee benefit plans, incurred by EPCO in managing and operating us and
our subsidiaries in accordance with the ASA.
(8)
Includes
TCO purchases of petroleum products from Jonah and Seaway and pipeline
transportation expense from Seaway.
(9)
Includes
rental expense and other operating expense.
(10) Includes
reimbursement for operating payroll, payroll related expenses, certain
repairs and maintenance expenses and insurance premiums on our equipment
under the transitional operating agreement with Cenac Towing Co., Inc. and
Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of
Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”)
pursuant to which, our fleet of acquired tow boats and tank barges
(including those acquired from Horizon Maritime, L.L.C. (“Horizon”)) are
operated by employees of Cenac for a period of up to two years following
the acquisition.
(11) Includes
reimbursement for administrative payroll and payroll related expenses, as
well as payment of a $42 thousand monthly service fee and a 5% overhead
fee charged on direct costs incurred by Cenac to operate the marine assets
in accordance with the transitional operating agreement.
|
||||||||
24
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The
following table summarizes related party balances at the dates
indicated:
|
March
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Accounts
receivable, related parties (1)
|
$ | 10.7 | $ | 15.8 | ||||
|
Accounts
payable, related parties (2)
|
20.6 | 17.2 | ||||||
|
(1)
Relates
to sales and transportation services provided to Enterprise Products
Partners and certain of its subsidiaries and EPCO and certain of its
affiliates and direct payroll, payroll related costs and other operational
expenses charged to unconsolidated affiliates.
(2)
Relates
to direct payroll, payroll related costs and other operational related
charges from Enterprise Products Partners and certain of its subsidiaries
and EPCO and certain of its affiliates, transportation and other services
provided by unconsolidated affiliates, advances from Seaway for operating
expenses and $3.9 million related to operational related charges from
Cenac.
|
||||||||
As an affiliate of EPCO and other
companies controlled by Mr. Duncan, our transactions and agreements with them
are not necessarily on an arm’s length basis. As a result, we cannot
provide assurance that the terms and provisions of such transactions or
agreements are at least 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:
|
§
|
EPCO
and its privately-held
subsidiaries;
|
|
§
|
Texas
Eastern Products Pipeline Company, LLC, our General
Partner;
|
|
§
|
Enterprise
GP Holdings, which owns and controls our General
Partner;
|
|
§
|
Enterprise
Products Partners, which is controlled by affiliates of EPCO, including
Enterprise GP Holdings;
|
|
§
|
Duncan
Energy Partners, which is controlled by affiliates of
EPCO;
|
|
§
|
Enterprise
Gas Processing LLC, which is controlled by affiliates of EPCO and is our
joint venture partner in Jonah;
|
|
§
|
Enterprise
Offshore Port System, LLC, which is controlled by affiliates of EPCO and
was one of our partners in Texas Offshore Port System;
and
|
|
§
|
the
Employee Partnerships, which are controlled by EPCO (see Note
3).
|
See Note 17 for information regarding
our dissociation and that of Enterprise Offshore Port System, LLC from the Texas
Offshore Port System partnership in April 2009.
In April 2009, we announced a proposal
made by Enterprise Products Partners in March 2009 to acquire all of our
outstanding partnership interests. See Note 17 for further
information regarding this subsequent event.
Dan L. Duncan directly owns and
controls EPCO and, through Dan Duncan LLC, owns and controls EPE Holdings, LLC,
the general partner of Enterprise GP Holdings. Enterprise GP Holdings
owns all of the membership interests of our General Partner. The
principal business activity of our General Partner is to act as our managing
partner. The executive officers of our General Partner are employees
of EPCO (see Note 1).
We and our General Partner are both
separate legal entities apart from each other and apart from EPCO and its other
affiliates, with assets and liabilities that are separate from those of EPCO and
its other affiliates. EPCO and its consolidated privately-held
subsidiaries and affiliates depend on the cash distributions they receive from
our General Partner and other investments to fund their operations and
to
25
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
meet
their debt obligations. We paid cash distributions to our General
Partner of $15.4 million and $12.4 million during the three months ended March
31, 2009 and 2008, respectively.
The limited partner interests in us
that are owned or controlled by EPCO and certain of its affiliates, other than
those interests owned by 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. All of the membership
interests in our General Partner and the limited partner interests in us that
are owned or controlled by Enterprise GP Holdings are pledged as security under
its credit facility. If Enterprise GP Holdings were to default under
its credit facility, its lender banks could own our General
Partner.
EPCO
Administrative Services Agreement. We have no
employees. We are managed by our General Partner, and all of our
management, administrative and operating functions are performed by employees of
EPCO, pursuant to the ASA or by other service providers. We,
Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings and
our respective general partners are among the parties to the ASA. The
Audit, Conflicts and Governance Committee (“ACG Committee”) of each general
partner has approved the ASA.
Under the ASA, we reimburse EPCO for
all costs and expenses it incurs in providing management, administrative and
operating services for us, including compensation of employees (i.e., salaries,
medical benefits and retirement benefits) (see Note 1). Since the
vast majority of such expenses are charged to us on an actual basis (i.e., no
mark-up or subsidy is charged or received by EPCO), we believe that such
expenses are representative of what the amounts would have been on a standalone
basis. With respect to allocated costs, we believe that the
proportional direct allocation method employed by EPCO is reasonable and
reflective of the estimated level of costs we would have incurred on a
standalone basis.
On January 30, 2009, we entered into
the Fifth Amended and Restated ASA, which amended the previous ASA to provide
for the cash reimbursement to EPCO by us of distributions of cash or securities,
if any, made by TEPPCO Unit II to its Class B limited partner, Mr. Jerry
Thompson, our chief executive officer and an employee of EPCO. The
Fifth Amended and Restated ASA also extends the term of EPCO’s service
obligations from December 2010 to December 2013.
Jonah
Joint Venture. Enterprise
Products Partners (through an affiliate) is our joint venture partner in Jonah,
the partnership through which we have owned our interest in the system serving
the Jonah and Pinedale fields. Through March 31, 2009, we have reimbursed
Enterprise Products Partners $308.5 million ($2.0 million in 2009, $44.9
million in 2008, $152.2 million in 2007 and $109.4 million in 2006) for our
share of the Phase V cost incurred by it (including its cost of capital incurred
prior to the formation of the joint venture of $1.3 million). At
March 31, 2009 and December 31, 2008, we had payables to Enterprise Products
Partners for costs incurred of $0.2 million and $1.0 million,
respectively. At March 31, 2009 and December 31, 2008, we had
receivables from Jonah of $8.4 million and $4.7 million, respectively, for
operating expenses. During the three months ended March 31, 2009 and
2008, we received distributions from Jonah of $38.9 million and $37.2 million,
respectively. During the three months ended March 31, 2009 and 2008,
Jonah paid distributions of $9.3 million and $8.9 million, respectively, to the
affiliate of Enterprise Products Partners that is our joint venture
partner.
Ownership
of our
General
Partner by Enterprise GP
Holdings; Relationship with Energy Transfer Equity. Enterprise GP
Holdings owns and controls the 2% general partner interest in us and has the
right (through its 100% ownership of our General Partner) to receive the
incentive distribution rights associated with the general partner
interest. Enterprise GP Holdings, DFIGP and other entities controlled
by Mr. Duncan own 17,073,315 of our Units.
26
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Enterprise GP Holdings acquired equity
method investments in Energy Transfer Equity, L.P. (“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.
Relationship with Unconsolidated
Affiliates
Our significant related party revenues
and expense transactions with unconsolidated affiliates consist of management,
rental and other revenues, transportation expense related to movements on
Centennial and Seaway and rental expense related to the lease of pipeline
capacity on Centennial. For additional information regarding our
unconsolidated affiliates, see Note 7.
See “Jonah Joint Venture” within this
Note 12 for a description of ongoing transactions involving our Jonah joint
venture with Enterprise Products Partners.
The following table presents the net
income available to our General Partner for the periods indicated for purposes
of calculating earnings per Unit:
|
For
the Three Months
|
|||||
|
Ended
March 31,
|
|||||
|
2009
|
2008
|
||||
|
Net
income attributable to TEPPCO Partners, L.P.
|
$ 78.2
|
$ 64.1
|
|||
|
Distributions Declared During
Quarter:
|
|||||
|
Distributions
to General Partner (including incentive distributions)
|
$ 15.4
|
$ 13.6
|
|||
|
Distributions
to limited partners
|
76.0
|
67.3
|
|||
|
Total
distributions declared during quarter
|
$ 91.4
|
$ 80.9
|
|||
|
Excess
of distributions over net income
|
$ (13.2)
|
$ (16.8)
|
|||
|
General
Partner’s interest in net income
|
16.93%
|
16.74%
|
|||
|
Earnings
allocation adjustment to General Partner under EITF 07-4
(1)
|
$ (2.2)
|
$ (2.9)
|
|||
|
Distributions
to General Partner (including incentive distributions)
|
$ 15.4
|
$ 13.6
|
|||
|
Earnings
allocation adjustment to General Partner under EITF 07-4
|
(2.2)
|
(2.9)
|
|||
|
Net
income available to our General Partner
|
$ 13.2
|
$ 10.7
|
|||
|
(1)
For
purposes of computing basic and diluted earnings per Unit, we used the
provisions of EITF 07-4, Application of the Two-Class
Method under FASB Statement No. 128 to Master Limited
Partnerships. Our earnings are allocated on a basis consistent
with distributions declared during the quarter (see Note 10).
|
|||||
27
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents our
calculation of basic and diluted earnings per Unit for the periods
indicated:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
BASIC
EARNINGS PER UNIT:
|
||||||||
|
Numerator:
|
||||||||
|
Limited partners’ interest in net income
|
$ | 65.0 | $ | 53.4 | ||||
|
Denominator:
|
||||||||
|
Weighted average Units
|
104.6 | 93.1 | ||||||
|
Weighted average time-vested restricted units
|
0.1 | 0.1 | ||||||
|
Total
|
104.7 | 93.2 | ||||||
|
Basic earnings per
Unit:
|
||||||||
|
Net income attributable to TEPPCO Partners, L.P.
|
$ | 0.75 | $ | 0.69 | ||||
|
General Partner’s interest in net income
|
(0.13 | ) | (0.12 | ) | ||||
|
Limited partners’ interest in net income
|
$ | 0.62 | $ | 0.57 | ||||
|
DILUTED
EARNINGS PER UNIT:
|
||||||||
|
Numerator:
|
||||||||
|
Limited partners’ interest in net income
|
$ | 65.0 | $ | 53.4 | ||||
|
Denominator:
|
||||||||
|
Weighted average Units
|
104.6 | 93.1 | ||||||
|
Weighted average time-vested restricted units
|
0.1 | 0.1 | ||||||
|
Weighted average incremental option units
|
* | -- | ||||||
|
Total
|
104.7 | 93.2 | ||||||
|
Diluted earnings per
Unit:
|
||||||||
|
Net income attributable to TEPPCO Partners, L.P.
|
$ | 0.75 | $ | 0.69 | ||||
|
General Partner’s interest in net income
|
(0.13 | ) | (0.12 | ) | ||||
|
Limited partners’ interest in net income
|
$ | 0.62 | $ | 0.57 | ||||
|
*Amount
is negligible.
|
||||||||
Our General Partner’s percentage
interest in our net income increases as cash distributions paid per Unit
increase, in accordance with our Partnership Agreement. At March 31,
2009 and 2008, we had outstanding 104,767,316 and 94,839,660 Units,
respectively.
Litigation
In 1991, we were named as a defendant
in a matter styled Jimmy R.
Green, et al. v. Cities Service Refinery, et al. as filed in the 26th
Judicial District Court of Bossier Parish, Louisiana. The plaintiffs
in this matter reside or formerly resided on land that was once the site of a
refinery owned by one of our co-defendants. The former refinery is
located near our Bossier City facility. Plaintiffs have claimed
personal injuries and property damage arising from alleged contamination of the
refinery property. The plaintiffs have pursued certification as a
class and their last demand had been approximately $175.0 million. Following a
hearing, the trial court ruled that the prerequisites for certifying a class do
not exist. We expect that a final order dismissing the matter is
forthcoming. Accordingly, we do not believe that the outcome of this
lawsuit will have a material adverse effect on our financial position, results
of operations or cash flows.
On September 18, 2006, Peter
Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court
of Chancery of the State of Delaware, in his individual capacity, as a putative
class action on behalf of our other unitholders, and derivatively on our behalf,
concerning proposals made to our unitholders in our definitive proxy statement
filed with the SEC on September 11, 2006 (“Proxy
28
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Statement”)
and other transactions involving us and Enterprise Products Partners or its
affiliates. Mr. Brinckerhoff filed an amended complaint on July 12,
2007. The amended complaint names as defendants the General Partner;
the Board of Directors of the General Partner; EPCO; Enterprise Products
Partners and certain of its affiliates and Dan L. Duncan. We are
named as a nominal defendant.
The amended complaint alleges, among
other things, that certain of the transactions adopted at a special meeting of
our unitholders on December 8, 2006, including a reduction of the General
Partner’s maximum percentage interest in our distributions in exchange for Units
(the “Issuance Proposal”), were unfair to our unitholders and constituted a
breach by the defendants of fiduciary duties owed to our unitholders and that
the Proxy Statement failed to provide our unitholders with all material facts
necessary for them to make an informed decision whether to vote in favor of or
against the proposals. The amended complaint further alleges that,
since Mr. Duncan acquired control of the General Partner in 2005, the
defendants, in breach of their fiduciary duties to us and our unitholders, have
caused us to enter into certain transactions with Enterprise Products Partners
or its affiliates that were unfair to us or otherwise unfairly favored
Enterprise Products Partners or its affiliates over us. The amended
complaint alleges that such transactions include the Jonah joint venture entered
into by us and an Enterprise Products Partners affiliate in August 2006 (citing
the fact that our ACG Committee did not obtain a fairness opinion from an
independent investment banking firm in approving the transaction), and the sale
by us to an Enterprise Products Partners’ affiliate of the Pioneer plant in
March 2006. As more fully described in the Proxy Statement, the ACG
Committee recommended the Issuance Proposal for approval by the Board of
Directors of the General Partner. The amended complaint also alleges
that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting
the three members of the ACG Committee at the time, cannot be considered
independent because of their alleged ownership of securities in Enterprise
Products Partners and its affiliates and/or their relationships with Mr.
Duncan.
The amended complaint seeks relief (i)
awarding damages for profits and special benefits allegedly obtained by
defendants as a result of the alleged wrongdoings in the complaint; (ii)
rescinding all actions taken pursuant to the Proxy vote and (iii) awarding
plaintiff costs of the action, including fees and expenses of his attorneys and
experts. By its Opinion and Order dated November 25, 2008, the Court
of Chancery dismissed Mr. Brinckerhoff’s individual and putative class action
claims with respect to the amendments to our partnership
agreement. Pre-trial discovery in this proceeding is
underway. Although we believe there are valid defenses to the claims
and we will defend ourselves vigorously, this lawsuit is at an early stage, and
in view of the inherent risks and unpredictability of litigation,
no assurance can be given as to the outcome of this
litigation.
In October 2005, Williams Gas
Processing, n/k/a Williams Field Services Company, LLC (“Williams”) notified
Jonah that the gas delivered to Williams’ Opal Gas Processing Plant (“Opal
Plant”) allegedly failed to conform to quality specifications of the
Interconnect and Operator Balancing Agreement (“Interconnect Agreement”) which
has allegedly caused damages to the Opal Plant in excess of $28.0 million.
On July 24, 2007, Jonah filed suit against Williams in Harris County, Texas
seeking a declaratory order that Jonah was not liable to Williams. In
addition, on August 24, 2007, Williams filed a complaint in the 3rd Judicial
District Court of Lincoln County, Wyoming alleging that Jonah was delivering
non-conforming gas from its gathering customers in the Jonah system to the Opal
Plant, in violation of the Interconnect Agreement. Jonah denies any
liability to Williams. Discovery is ongoing.
See Note 17 for a subsequent event
regarding new litigation involving us and Enterprise Products
Partners.
In addition to the proceedings
discussed above, we have been, in the ordinary course of business, a defendant
in various lawsuits and a party to various other legal proceedings, some of
which are covered in whole or in part by insurance. We believe that the outcome
of these other proceedings will not individually
29
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
or in the
aggregate have a future material adverse effect on our consolidated financial
position, results of operations or cash flows.
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 in our financial statements.
Regulatory
Matters
Our pipelines and other facilities are
subject to multiple environmental obligations and potential liabilities under a
variety of federal, state and local laws and regulations. These include, without
limitation: the Comprehensive Environmental Response, Compensation, and
Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act;
the Federal Water Pollution Control Act or the Clean Water Act; the Oil
Pollution Act; and analogous state and local laws and regulations. Such laws and
regulations affect many aspects of our present and future operations, and
generally require us to obtain and comply with a wide variety of environmental
registrations, licenses, permits, inspections and other approvals, with respect
to air emissions, water quality, wastewater discharges, and solid and hazardous
waste management. Failure to comply with these requirements may expose us to
fines, penalties and/or interruptions in our operations that could influence our
results of operations. If an accidental leak, spill or release of hazardous
substances occurs at any facilities that we own, operate or otherwise use, or
where we send materials for treatment or disposal, we could be held jointly and
severally liable for all resulting liabilities, including investigation,
remedial and clean-up costs. Likewise, we could be required to remove or
remediate previously disposed wastes or property contamination, including
groundwater contamination. Any or all of this could materially affect
our results of operations and cash flows.
We believe that our operations and
facilities are in substantial compliance with applicable environmental laws and
regulations, and that the cost of compliance with such laws and regulations will
not have a material adverse effect on our results of operations or financial
position. We cannot ensure, however, that existing environmental regulations
will not be revised or that new regulations will not be adopted or become
applicable to us. The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may be perceived to affect the
environment; and thus there can be no assurance as to the amount or timing of
future expenditures for environmental regulation compliance or remediation, and
actual future expenditures may be different from the amounts we currently
anticipate. Revised or additional regulations that result in increased
compliance costs or additional operating restrictions, particularly if those
costs are not fully recoverable from our customers, could have a material
adverse effect on our business, financial position, results of operations and
cash flows. At March 31, 2009 and December 31, 2008, our accrued
liabilities for environmental remediation projects totaled $6.9
million.
In 1999, our Arcadia, Louisiana
facility and adjacent terminals were directed by the Remediation Services
Division of the Louisiana Department of Environmental Quality (“LDEQ”) to pursue
remediation of environmental contamination. Effective March 2004, we
executed an access agreement with an adjacent industrial landowner who is
located upgradient of the Arcadia facility. This agreement enables
the landowner to proceed with remediation activities at our Arcadia facility for
which it has accepted shared responsibility. At March 31, 2009, we
have an accrued liability of $0.5 million for remediation costs at our Arcadia
facility. We do not expect that the completion of the remediation
program proposed to the LDEQ will have a future material adverse effect on our
financial position, results of operations or cash flows.
We received
a notice of probable violation from the U.S. Department of Transportation on
April 25, 2005 for alleged violations of pipeline safety regulations at our
Todhunter facility, with a proposed $0.4
30
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
million
civil penalty. We responded on June 30, 2005 by admitting certain of
the alleged violations, contesting others and requesting a reduction in the
proposed civil penalty. We do not expect any settlement, fine or
penalty to have a material adverse effect on our financial position, results of
operations or cash flows.
The Federal
Energy Regulatory Commission (“FERC”), pursuant to the Interstate Commerce Act
of 1887, as amended, the Energy Policy Act of 1992 and rules and orders
promulgated thereunder, regulates the tariff rates for our interstate common
carrier pipeline operations. To be lawful under that Act, interstate
tariff rates, terms and conditions of service must be just and reasonable and
not unduly discriminatory, and must be on file with FERC. In
addition, pipelines may not confer any undue preference upon any
shipper. Shippers may protest, and the FERC may investigate, the
lawfulness of new or changed tariff rates. The FERC can suspend those
tariff rates for up to seven months. It can also require refunds of
amounts collected with interest pursuant to rates that are ultimately found to
be unlawful. The FERC and interested parties can also challenge
tariff rates that have become final and effective. Because of the
complexity of rate making, the lawfulness of any rate is never
assured. A successful challenge of our rates could adversely affect
our revenues.
The FERC uses prescribed rate
methodologies for approving regulated tariff rates for transporting crude oil
and refined products. Our interstate tariff rates are either
market-based or derived in accordance with the FERC’s indexing methodology,
which currently allows a pipeline to increase its rates by a percentage linked
to the producer price index for finished goods. These methodologies
may limit our ability to set rates based on our actual costs or may delay the
use of rates reflecting increased costs. Changes in the FERC’s
approved methodology for approving rates could adversely affect
us. Adverse decisions by the FERC in approving our regulated rates
could adversely affect our cash flow.
The intrastate liquids pipeline
transportation and gas gathering services we provide are subject to various
state laws and regulations that apply to the rates we charge and the terms and
conditions of the services we offer. Although state regulation
typically is less onerous than FERC regulation, the rates we charge and the
provision of our services may be subject to challenge.
Although our natural gas gathering
systems are generally exempt from FERC regulation under the Natural Gas Act of
1938, FERC regulation still significantly affects our natural gas gathering
business. Our natural gas gathering operations could be adversely
affected in the future should they become subject to the application of federal
regulation of rates and services or if the states in which we operate adopt
policies imposing more onerous regulation on gathering. Additional
rules and legislation pertaining to these matters are considered and adopted
from time to time at both state and federal levels. We cannot predict
what effect, if any, such regulatory changes and legislation might have on our
operations or revenues.
Contractual
Obligations
Scheduled
maturities of long-term debt. With the
exception of routine fluctuations in the balance of our Revolving Credit
Facility, there have been no material changes in our scheduled maturities of
long-term debt since those reported in our Annual Report on Form 10-K for the
year ended December 31, 2008.
Operating
lease obligations. Lease and rental
expense was $4.5 million and $5.4 million during the three months ended March
31, 2009 and 2008, respectively. There have been no material changes
in our operating lease commitments since December 31, 2008.
Purchase
obligations. Apart from that
discussed below, there have been no material changes in our purchase obligations
since December 31, 2008.
31
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Due to our exit from the Texas Offshore
Port System partnership, our capital expenditure commitments decreased by an
estimated $68.0 million. See Note 17 for additional information
regarding this subsequent event.
Other
Guarantees. At March 31,
2009 and December 31, 2008, Centennial’s debt obligations consisted of $127.4
million and $129.9 million, respectively, borrowed under a master shelf loan
agreement. We, TE Products, TEPPCO Midstream and TCTM (collectively,
the “TEPPCO Guarantors”) are required, on a joint and several basis, to pay 50%
of any past-due amount under Centennial’s master shelf loan agreement not paid
by Centennial. We may be required to provide additional credit
support in the form of a letter of credit or pay certain fees if either of our
credit ratings from Standard & Poor’s Ratings Group and Moody’s Investors
Service, Inc. falls below investment grade levels. If Centennial
defaults on its debt obligations, the estimated maximum potential amount of
future payments for the TEPPCO Guarantors and Marathon Petroleum Company LLC
(“Marathon”) is $63.7 million each at March 31, 2009. At March 31,
2009, we have a liability of $8.8 million, which is based upon the expected
present value of amounts we would have to pay under the guarantee.
TE Products, Marathon and Centennial
have also entered into a limited cash call agreement, which allows each member
to contribute cash in lieu of Centennial procuring separate insurance in the
event of a third-party liability arising from a catastrophic
event. There is an indefinite term for the agreement and each member
is to contribute cash in proportion to its ownership interest, up to a maximum
of $50.0 million each. As a result of the catastrophic event
guarantee, at March 31, 2009, TE Products has a liability of $3.8 million, which
is based upon the expected present value of amounts we would have to pay under
the guarantee. If a catastrophic event were to occur and we were
required to contribute cash to Centennial, such contributions might be covered
by our insurance (net of deductible), depending upon the nature of the
catastrophic event.
Motiva
Project. In December
2006, we signed an agreement with Motiva Enterprises, LLC (“Motiva”) for us to
construct and operate a new refined products storage facility to support the
expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms
of the agreement, we are constructing a 5.4 million barrel refined products
storage facility for gasoline and distillates. The agreement also
provides for a 15-year throughput and dedication of volume, which will commence
upon completion of the refinery expansion or July 1, 2010, whichever comes
first. Through March 31, 2009, we have spent approximately $220.0
million on this construction project. Under the terms of the
agreement, if Motiva cancels the agreement prior to the commencement date of the
project, Motiva will reimburse us the actual reasonable expenses we have
incurred after the effective date of the agreement, including both internal and
external costs that would be capitalized as a part of the project, plus a ten
percent cancellation fee.
Texas
Offshore Port System. We, through a
subsidiary, owned a one-third interest in the Texas Offshore Port System
partnership until April 16, 2009. We had guaranteed up to
approximately $700.0 million of the project costs to be incurred by this
partnership. Upon our dissociation (see Note 17), our obligations
under this commitment terminated.
32
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table provides
information regarding (i) the net effect of changes in our operating assets and
liabilities, (ii) non-cash investing and financing activities and (iii) cash
payments for interest for the periods indicated:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Decrease
(increase) in:
|
||||||||
|
Accounts
receivable, trade
|
$ | 48.7 | $ | (189.2 | ) | |||
|
Accounts
receivable, related parties
|
5.9 | 1.5 | ||||||
|
Inventories
|
0.3 | (7.2 | ) | |||||
|
Other
current assets
|
1.1 | (2.8 | ) | |||||
|
Other
|
0.3 | (4.3 | ) | |||||
|
Increase
(decrease) in:
|
||||||||
|
Accounts
payable and accrued liabilities
|
(28.9 | ) | 157.7 | |||||
|
Accounts
payable, related parties
|
3.5 | (6.9 | ) | |||||
|
Other
|
(8.4 | ) | (11.5 | ) | ||||
|
Net
effect of changes in operating accounts
|
$ | 22.5 | $ | (62.7 | ) | |||
|
Non-cash
investing activities:
|
||||||||
|
Payable
to Enterprise Gas Processing, LLC for spending for
Phase
V expansion of Jonah Gas Gathering Company
|
$ | 0.2 | $ | 7.4 | ||||
|
Liabilities
for construction work in progress
|
$ | 18.2 | $ | 16.6 | ||||
|
Non-cash
financing activities:
|
||||||||
|
Issuance
of Units in Cenac acquisition
|
$ | -- | $ | 186.6 | ||||
|
Supplemental
disclosure of cash flows:
|
||||||||
|
Cash
paid for interest (net of amounts capitalized)
|
$ | 22.1 | $ | 47.4 | ||||
The
Guarantor Subsidiaries have issued full, unconditional, and joint and several
guarantees of our senior notes, our Junior Subordinated Notes (collectively
“the Guaranteed Debt”) and our Revolving Credit Facility.
The following supplemental condensed
consolidating financial information reflects our separate accounts, the combined
accounts of the Guarantor Subsidiaries, the combined accounts of our other
non-guarantor subsidiaries, the combined consolidating adjustments and
eliminations and our consolidated accounts for the dates and periods
indicated. For purposes of the following consolidating information,
our investments in our subsidiaries and the Guarantor Subsidiaries’ investments
in their subsidiaries are accounted for under the equity method of
accounting. Earnings of subsidiaries are therefore reflected in the
Partnership’s and Guarantor Subsidiaries’ investment accounts and
earnings. The elimination entries presented herein eliminate
investments in subsidiaries and intercompany balances and
transactions.
33
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
March
31, 2009
|
||||||||||||||||||||
|
TEPPCO
Partners, L.P.
|
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiaries
|
Consolidating
Adjustments
|
TEPPCO
Partners, L.P. Consolidated
|
||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Current
assets
|
$ | 15.6 | $ | 78.8 | $ | 1,171.0 | $ | (424.9 | ) | $ | 840.5 | |||||||||
|
Property,
plant and equipment – net
|
13.6 | 1,360.9 | 1,142.7 | -- | 2,517.2 | |||||||||||||||
|
Investments
in unconsolidated affiliates
|
8.8 | 1,017.7 | 218.3 | -- | 1,244.8 | |||||||||||||||
|
Investments
in consolidated affiliates
|
1,673.0 | 441.6 | -- | (2,114.6 | ) | -- | ||||||||||||||
|
Goodwill
|
-- | -- | 106.6 | -- | 106.6 | |||||||||||||||
|
Intercompany
notes receivable
|
2,789.1 | -- | -- | (2,789.1 | ) | -- | ||||||||||||||
|
Intangible
assets
|
-- | 115.3 | 87.0 | -- | 202.3 | |||||||||||||||
|
Other
assets
|
13.9 | 33.2 | 84.2 | -- | 131.3 | |||||||||||||||
|
Total
assets
|
$ | 4,514.0 | $ | 3,047.5 | $ | 2,809.8 | $ | (5,328.6 | ) | $ | 5,042.7 | |||||||||
|
Liabilities
and partners’ capital
|
||||||||||||||||||||
|
Current
liabilities
|
$ | 345.6 | $ | 149.6 | $ | 784.1 | $ | (424.9 | ) | $ | 854.4 | |||||||||
|
Long-term
debt
|
2,577.3 | -- | -- | -- | 2,577.3 | |||||||||||||||
|
Intercompany
notes payable
|
-- | 1,503.6 | 1,285.5 | (2,789.1 | ) | -- | ||||||||||||||
|
Other
long-term liabilities
|
8.6 | 16.9 | 3.0 | -- | 28.5 | |||||||||||||||
|
Total
partners’ capital
|
1,582.5 | 1,377.4 | 737.2 | (2,114.6 | ) | 1,582.5 | ||||||||||||||
|
Total
liabilities and partners’ capital
|
$ | 4,514.0 | $ | 3,047.5 | $ | 2,809.8 | $ | (5,328.6 | ) | $ | 5,042.7 | |||||||||
|
December
31, 2008
|
||||||||||||||||||||
|
TEPPCO
Partners, L.P.
|
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiaries
|
Consolidating
Adjustments
|
TEPPCO
Partners, L.P. Consolidated
|
||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Current
assets
|
$ | 23.1 | $ | 145.2 | $ | 1,148.0 | $ | (408.7 | ) | $ | 907.6 | |||||||||
|
Property,
plant and equipment – net
|
13.5 | 1,294.8 | 1,131.6 | -- | 2,439.9 | |||||||||||||||
|
Investments
in unconsolidated affiliates
|
9.0 | 1,020.9 | 226.0 | -- | 1,255.9 | |||||||||||||||
|
Investments
in consolidated affiliates
|
1,686.0 | 399.0 | -- | (2,085.0 | ) | -- | ||||||||||||||
|
Goodwill
|
-- | -- | 106.6 | -- | 106.6 | |||||||||||||||
|
Intercompany
notes receivable
|
2,628.3 | -- | -- | (2,628.3 | ) | -- | ||||||||||||||
|
Intangible
assets
|
-- | 118.0 | 89.7 | -- | 207.7 | |||||||||||||||
|
Other
assets
|
14.4 | 33.3 | 84.4 | -- | 132.1 | |||||||||||||||
|
Total
assets
|
$ | 4,374.3 | $ | 3,011.2 | $ | 2,786.3 | $ | (5,122.0 | ) | $ | 5,049.8 | |||||||||
|
Liabilities
and partners’ capital
|
||||||||||||||||||||
|
Current
liabilities
|
$ | 244.5 | $ | 215.4 | $ | 848.8 | $ | (408.7 | ) | $ | 900.0 | |||||||||
|
Long-term
debt
|
2,529.6 | -- | -- | -- | 2,529.6 | |||||||||||||||
|
Intercompany
notes payable
|
-- | 1,424.3 | 1,204.0 | (2,628.3 | ) | -- | ||||||||||||||
|
Other
long-term liabilities
|
8.7 | 17.0 | 3.0 | -- | 28.7 | |||||||||||||||
|
Total
partners’ capital
|
1,591.5 | 1,354.5 | 730.5 | (2,085.0 | ) | 1,591.5 | ||||||||||||||
|
Total
liabilities and partners’ capital
|
$ | 4,374.3 | $ | 3,011.2 | $ | 2,786.3 | $ | (5,122.0 | ) | $ | 5,049.8 | |||||||||
34
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
For
the Three Months Ended March 31, 2009
|
||||||||||||||||||||
|
TEPPCO
Partners, L.P.
|
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiaries
|
Consolidating
Adjustments
|
TEPPCO
Partners, L.P. Consolidated
|
||||||||||||||||
|
Operating
revenues
|
$ | -- | $ | 100.7 | $ | 1,356.9 | $ | -- | $ | 1,457.6 | ||||||||||
|
Costs
and expenses
|
-- | 68.0 | 1,304.6 | (0.7 | ) | 1,371.9 | ||||||||||||||
|
Operating income
|
-- | 32.7 | 52.3 | 0.7 | 85.7 | |||||||||||||||
|
Interest
expense
|
-- | (20.3 | ) | (11.8 | ) | -- | (32.1 | ) | ||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
78.2 | 65.4 | 3.3 | (121.8 | ) | 25.1 | ||||||||||||||
|
Other,
net
|
-- | 0.3 | -- | -- | 0.3 | |||||||||||||||
|
Income before provision for income taxes
|
78.2 | 78.1 | 43.8 | (121.1 | ) | 79.0 | ||||||||||||||
|
Provision
for income taxes
|
-- | 0.3 | 0.5 | -- | 0.8 | |||||||||||||||
|
Net income
|
$ | 78.2 | $ | 77.8 | $ | 43.3 | $ | (121.1 | ) | $ | 78.2 | |||||||||
|
For
the Three Months Ended March 31, 2008
|
||||||||||||||||||||
|
TEPPCO
Partners, L.P.
|
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiaries
|
Consolidating
Adjustments
|
TEPPCO
Partners, L.P. Consolidated
|
||||||||||||||||
|
Operating
revenues
|
$ | -- | $ | 102.9 | $ | 2,705.6 | $ | -- | $ | 2,808.5 | ||||||||||
|
Costs
and expenses
|
-- | 67.9 | 2,660.0 | (2.9 | ) | 2,725.0 | ||||||||||||||
|
Operating income
|
-- | 35.0 | 45.6 | 2.9 | 83.5 | |||||||||||||||
|
Interest
expense
|
-- | (26.8 | ) | (11.8 | ) | -- | (38.6 | ) | ||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
64.1 | 53.0 | 3.0 | (100.4 | ) | 19.7 | ||||||||||||||
|
Other,
net
|
-- | 0.3 | -- | -- | 0.3 | |||||||||||||||
|
Income before provision for income taxes
|
64.1 | 61.5 | 36.8 | (97.5 | ) | 64.9 | ||||||||||||||
|
Provision
for income taxes
|
-- | 0.2 | 0.6 | -- | 0.8 | |||||||||||||||
|
Net income
|
$ | 64.1 | $ | 61.3 | $ | 36.2 | $ | (97.5 | ) | $ | 64.1 | |||||||||
35
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
For
the Three Months Ended March 31, 2009
|
||||||||||||||||||||
|
TEPPCO
Partners, L.P.
|
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiaries
|
Consolidating
Adjustments
|
TEPPCO
Partners, L.P. Consolidated
|
||||||||||||||||
|
Operating
activities:
|
||||||||||||||||||||
|
Net income
|
$ | 78.2 | $ | 77.8 | $ | 43.3 | $ | (121.1 | ) | $ | 78.2 | |||||||||
|
Adjustments to reconcile net income to net cash
|
||||||||||||||||||||
|
from operating activities:
|
||||||||||||||||||||
|
Depreciation and amortization
|
-- | 17.8 | 15.2 | -- | 33.0 | |||||||||||||||
|
Equity in earnings of unconsolidated
affiliates
|
-- | (22.5 | ) | (3.3 | ) | 0.7 | (25.1 | ) | ||||||||||||
|
Distributions received from unconsolidated
affiliates
|
-- | 38.9 | 8.8 | -- | 47.7 | |||||||||||||||
|
Other, net
|
7.8 | (24.9 | ) | (88.0 | ) | 127.9 | 22.8 | |||||||||||||
|
Net cash from operating activities
|
86.0 | 87.1 | (24.0 | ) | 7.5 | 156.6 | ||||||||||||||
|
Cash
flows from investing activities:
|
||||||||||||||||||||
|
Investment in Jonah
|
-- | (12.3 | ) | -- | -- | (12.3 | ) | |||||||||||||
|
Investment in Texas Offshore Port System
|
-- | -- | 1.7 | -- | 1.7 | |||||||||||||||
|
Capital expenditures
|
-- | (77.0 | ) | (24.6 | ) | -- | (101.6 | ) | ||||||||||||
|
Other, net
|
-- | (1.4 | ) | -- | -- | (1.4 | ) | |||||||||||||
|
Net cash flows from investing activities
|
-- | (90.7 | ) | (22.9 | ) | -- | (113.6 | ) | ||||||||||||
|
Cash
flows from financing activities:
|
||||||||||||||||||||
|
Borrowings under debt agreements
|
301.8 | -- | -- | -- | 301.8 | |||||||||||||||
|
Repayments of debt
|
(252.8 | ) | -- | -- | -- | (252.8 | ) | |||||||||||||
|
Net proceeds from issuance of limited partner
units
|
-- | -- | -- | 1.6 | 1.6 | |||||||||||||||
|
Intercompany debt activities
|
(48.9 | ) | 76.7 | 83.4 | (111.2 | ) | -- | |||||||||||||
|
Distributions paid to partners
|
(91.4 | ) | (73.1 | ) | (36.5 | ) | 109.6 | (91.4 | ) | |||||||||||
|
Net cash flows from financing activities
|
(91.3 | ) | 3.6 | 46.9 | -- | (40.8 | ) | |||||||||||||
|
Net change in cash and cash equivalents
|
(5.3 | ) | -- | -- | 7.5 | 2.2 | ||||||||||||||
|
Cash and cash equivalents, January 1
|
16.1 | -- | -- | (16.1 | ) | -- | ||||||||||||||
|
Cash and cash equivalents, March 31
|
$ | 10.8 | $ | -- | $ | -- | $ | (8.6 | ) | $ | 2.2 | |||||||||
36
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
For
the Three Months Ended March 31, 2008
|
||||||||||||||||||||
|
TEPPCO
Partners, L.P.
|
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiaries
|
Consolidating
Adjustments
|
TEPPCO
Partners, L.P. Consolidated
|
||||||||||||||||
|
Operating
activities:
|
||||||||||||||||||||
|
Net income
|
$ | 64.1 | $ | 61.3 | $ | 36.2 | $ | (97.5 | ) | $ | 64.1 | |||||||||
|
Adjustments to reconcile net income to net cash
|
||||||||||||||||||||
|
from operating activities:
|
||||||||||||||||||||
|
Depreciation and amortization
|
-- | 16.9 | 11.4 | -- | 28.3 | |||||||||||||||
|
Equity in earnings of unconsolidated
affiliates
|
-- | (19.6 | ) | (3.0 | ) | 2.9 | (19.7 | ) | ||||||||||||
|
Distributions received from unconsolidated
affiliates
|
-- | 37.2 | -- | -- | 37.2 | |||||||||||||||
|
Other, net
|
66.1 | 83.0 | (188.6 | ) | (11.7 | ) | (51.2 | ) | ||||||||||||
|
Net cash from operating activities
|
130.2 | 178.8 | (144.0 | ) | (106.3 | ) | 58.7 | |||||||||||||
|
Cash
flows from investing activities:
|
||||||||||||||||||||
|
Cash used for business combinations
|
-- | -- | (338.5 | ) | -- | (338.5 | ) | |||||||||||||
|
Investment in Jonah
|
-- | (31.8 | ) | -- | -- | (31.8 | ) | |||||||||||||
|
Capital expenditures
|
-- | (42.4 | ) | (9.2 | ) | -- | (51.6 | ) | ||||||||||||
|
Other, net
|
-- | (0.3 | ) | (14.3 | ) | -- | (14.6 | ) | ||||||||||||
|
Net cash flows from investing activities
|
-- | (74.5 | ) | (362.0 | ) | -- | (436.5 | ) | ||||||||||||
|
Cash
flows from financing activities:
|
||||||||||||||||||||
|
Borrowings under debt agreements
|
2,512.6 | -- | -- | -- | 2,512.6 | |||||||||||||||
|
Repayments of debt
|
(1,577.1 | ) | (361.6 | ) | (63.1 | ) | -- | (2,001.8 | ) | |||||||||||
|
Net proceeds from issuance of limited partner
units
|
2.7 | -- | -- | -- | 2.7 | |||||||||||||||
|
Debt issuance costs
|
(8.7 | ) | -- | -- | -- | (8.7 | ) | |||||||||||||
|
Settlement of interest rate derivative
instruments – treasury locks
|
(52.1 | ) | -- | -- | -- | (52.1 | ) | |||||||||||||
|
Intercompany debt activities
|
(935.5 | ) | 332.2 | 596.0 | 7.3 | -- | ||||||||||||||
|
Distributions paid to partners
|
(74.9 | ) | (74.9 | ) | (26.9 | ) | 101.8 | (74.9 | ) | |||||||||||
|
Net cash flows from financing activities
|
(133.0 | ) | (104.3 | ) | 506.0 | 109.1 | 377.8 | |||||||||||||
|
Net change in cash and cash equivalents
|
(2.8 | ) | -- | -- | 2.8 | -- | ||||||||||||||
|
Cash and cash equivalents, January 1
|
8.2 | -- | -- | (8.2 | ) | -- | ||||||||||||||
|
Cash and cash equivalents, March 31
|
$ | 5.4 | $ | -- | $ | -- | $ | (5.4 | ) | $ | -- | |||||||||
TEPPCO
Exits Texas Offshore Port System Partnership
On April
21, 2009, we announced that, effective April 16, 2009, our affiliate elected to
dissociate, or exit from, the Texas Offshore Port System partnership and forfeit
our investment and one-third ownership interest in the
partnership. An affiliate of Enterprise Products Partners also
elected to dissociate from the Texas Offshore Port System partnership at the
same time. As a result, we expect to record a non-cash charge of
approximately $34.2 million against our earnings for the second quarter of
2009. The decision to dissociate from the Texas Offshore Port System
partnership was in connection with a disagreement with one of our partners, an
affiliate of Oiltanking Holding Americas, Inc. (“Oiltanking”). The
total cost of the project had been estimated at $1.8 billion.
In a
response to the notices of dissociation, Oiltanking has alleged that the
dissociation of our affiliate and Enterprise Products Partners’ affiliate were
wrongful and in breach of the Texas Offshore Port System partnership
agreement. We believe that our actions in dissociating from the
partnership are
37
TEPPCO
PARTNERS, L.P.
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
permitted by, and in
accordance with, the terms of the Texas Offshore Port System partnership
agreement and, should the need arise, we intend to vigorously defend such
actions.
Discussions with Enterprise Products
Partners Regarding Potential Combinations
and Related
Matters
On April 29, 2009, we announced that we
received a proposal on March 9, 2009 from Enterprise Products Partners to
acquire all of our outstanding partnership interests (the “Proposed
Merger”). The proposed consideration for our Units consisted of 1.043
Enterprise Products Partners common units and $1.00 in cash for each of our
Units. In order to evaluate the Proposed Merger, our ACG Committee
formed a special committee consisting of Donald H. Daigle, Irvin Toole, Jr. and
Duke R. Ligon (the “Special Committee”). After considering Enterprise
Products Partners’ proposal with the assistance of its financial and legal
advisors, the Special Committee unanimously concluded that it did not support
the proposal and advised Enterprise Products Partners of its
decision. The Special Committee informed Enterprise Products Partners
that it remained willing to consider a revised proposal.
Our general partner and the general
partner of Enterprise Products Partners are owned by Enterprise GP Holdings,
which also owns approximately 4.2% and 3.0%, respectively, of the outstanding
limited partner units of us and Enterprise Products Partners.
We do not intend to comment further on
discussions with Enterprise Products Partners unless and until a definitive
agreement is reached and we give no assurance that any such agreement will be
executed or that any transaction will be approved or consummated.
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 Court
of Chancery of New Castle County in the State of Delaware, as putative
class actions on behalf of other unitholders of TEPPCO, concerning the Proposed
Merger. The complaints name as defendants our General Partner; Enterprise
Products Partners and its general partner; EPCO; Dan L. Duncan; and each of the
directors of our General Partner.
The
complaints allege, among other things, that the terms of the Proposed Merger are
grossly unfair to our unitholders, that Mr. Duncan and other defendants who
control us have acted to drive down the price of our Units and that the Proposed
Merger is an attempt to extinguish, without consideration and without adequate
information having been provided to our unitholders to cast a vote with respect
to the Proposed Merger, a separate derivative action that previously had been
filed in September 2006 by Mr. Brinckerhoff concerning proposals made in our
Proxy Statement and other transactions involving us and Enterprise Products
Partners or its affiliates. See Note 14 for additional information
regarding this proceeding. The complaints further allege that the process
through which a special committee of our ACG Committee was appointed to consider
the Proposed Merger is contrary to the spirit and intent of our partnership
agreement and constitutes a breach of the implied covenant of fair
dealing.
The complaints seek relief (i)
enjoining defendants and all persons acting in concert with them from pursuing
the Proposed Merger; (ii) rescinding the Proposed Merger to the extent it is
consummated or awarding rescissory damages in respect thereof; (iii) directing
defendants to account to plaintiffs and the purported class for all damages
suffered or to be suffered by them as a result of defendants’ alleged wrongful
conduct; and (iv) awarding plaintiffs costs of the actions, including fees and
expenses of their attorneys and experts.
For
the three months ended March 31, 2009 and 2008
The following information should be
read in conjunction with our unaudited condensed consolidated financial
statements and accompanying notes included in this Quarterly
Report. The following information and such unaudited condensed
consolidated financial statements should also be read in conjunction with the
financial statements and related notes, together with our discussion and
analysis of financial position and results of operations included in our Annual
Report on Form 10-K for the year ended December 31, 2008. Our
financial statements have been prepared in accordance with U.S. generally
accepted accounting principles (“GAAP”).
Key
References Used in this Quarterly Report
Unless the context requires otherwise,
references to “we,”
“us,” “our,” the “Partnership” or “TEPPCO” are intended to mean
the business and operations of TEPPCO Partners, L.P. and its consolidated
subsidiaries.
References to “TE Products,” “TCTM,” “TEPPCO Midstream” and “TEPPCO Marine Services” mean
TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC
and TEPPCO Marine Services, LLC, our subsidiaries.
References to “General Partner” mean Texas
Eastern Products Pipeline Company, LLC, which is the general partner of
TEPPCO.
References to “Enterprise GP Holdings” mean
Enterprise GP Holdings L.P., a publicly traded partnership that owns our General
Partner and Enterprise Products GP, LLC, the general partner of Enterprise
Products Partners L.P.
References to “Enterprise Products Partners”
mean Enterprise Products Partners L.P., a publicly traded Delaware limited
partnership and its consolidated subsidiaries, which is an affiliate of
ours.
References to “EPCO” mean EPCO, Inc., a
privately-held company that is affiliated with our General
Partner. Dan L. Duncan is the Group Co-Chairman and controlling
shareholder of EPCO.
As
generally used in the energy industry and in this discussion, the identified
terms have the following meanings:
|
/d
|
=
per day
|
|
|
Mcf
|
=
thousand cubic feet
|
|
|
MMcf
|
=
million cubic feet
|
|
|
Bcf
|
=
billion cubic feet
|
|
|
MMBbls
|
=
million barrels
|
|
|
MMBtus
|
=
million British thermal units
|
|
|
BBtus
|
=
billion British thermal
units
|
This
discussion contains various forward-looking statements and information that are
based on our beliefs and those of our General Partner, as well as assumptions
made by us and information currently available to us. When used in
this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,”
“goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,”
“potential” and similar expressions and statements regarding our plans and
objectives for future operations, are intended to identify forward-looking
statements. Although we and our General Partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our General Partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A “Risk Factors” included in our Annual Report on Form 10-K for the year
ended December 31, 2008 and in Part
II,
Item 1A of this Quarterly Report. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove incorrect, our
actual results may vary materially from those anticipated, estimated, projected
or expected. You should not put undue reliance on any forward-looking
statements. The forward-looking statements in this Quarterly Report
speak only as of the date hereof. Except as required by federal and
state securities laws, we undertake no obligation to publicly update or revise
any forward-looking statements, whether as a result of new information, future
events or any other reason.
Overview of Critical Accounting Policies and Estimates
A summary of the significant accounting
policies we have adopted and followed in the preparation of our consolidated
financial statements is included in our Annual Report on Form 10-K for the
year ended December 31, 2008. Certain of these accounting policies
require the use of estimates. As more fully described therein, the
following estimates, in our opinion, are subjective in nature, require the
exercise of judgment and involve complex analysis: revenue and expense accruals,
including accruals for power costs, property taxes and crude oil margins;
reserves for environmental matters; depreciation methods and estimated useful
lives of property, plant and equipment; measuring recoverability of long-lived
assets and equity method investments; measuring the fair value of goodwill; and
amortization methods and estimated useful lives of intangible
assets. These estimates are based on our knowledge and understanding
of current conditions and actions we may take in the future. Changes
in these estimates will occur as a result of the passage of time and the
occurrence of future events. Subsequent changes in these estimates
may have a significant impact on our financial position, results of operations
and cash flows.
Overview
of Business
We are a publicly traded, diversified
energy logistics partnership with operations that span much of the continental
United States. Our limited partner units (“Units”) are listed on the
New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. We
were formed in March 1990 as a Delaware limited partnership.
We own
and operate an extensive network of assets that facilitate the movement,
marketing, gathering and storage of various commodities and energy-related
products. Our pipeline
network gathers and transports refined products, crude oil, natural gas,
liquefied petroleum gases (“LPGs”) and natural gas liquids (“NGLs”), including
one of the largest common carrier pipelines for refined products and LPGs in the
United States. We also own 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, we own interests
in Seaway Crude Pipeline Company (“Seaway”), Centennial Pipeline LLC
(“Centennial”), Jonah Gas Gathering Company (“Jonah”) and an undivided ownership
interest in the Basin Pipeline (“Basin”). We operate and report in
four business segments:
|
§
|
pipeline
transportation, marketing and storage of refined products, LPGs and
petrochemicals (“Downstream
Segment”);
|
|
§
|
gathering,
pipeline transportation, marketing and storage of crude oil, distribution
of lubrication oils and specialty chemicals and fuel transportation
services (“Upstream Segment”);
|
|
§
|
gathering
of natural gas, fractionation of NGLs and pipeline transportation of NGLs
(“Midstream Segment”); and
|
|
§
|
marine
transportation of refined products, crude oil, condensate, asphalt, heavy
fuel oil and other heated oil products via tow boats and tank barges
(“Marine Services Segment”).
|
Our reportable segments offer different
products and services and are managed separately because each requires different
business strategies. We operate through TE Products, TCTM and TEPPCO
Midstream, and beginning February 1, 2008, through TEPPCO Marine
Services. Texas Eastern Products Pipeline Company, LLC, a Delaware
limited liability company, serves as our general partner and owns
a
2%
general partner interest in us. We refer to refined products, LPGs,
petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs,
natural gas, asphalt, heavy fuel oil and other heated oil products in this
Quarterly Report, collectively, as “petroleum products” or “products.”
Please refer to Item
7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Overview of Business in our Annual Report on Form 10-K
for the year ended December 31, 2008 for an overview of how revenues are earned
in each segment and other factors affecting the results and financial position
of our businesses.
Recent
Developments
The following information highlights
our significant developments since January 1, 2009 through the date of this
filing.
Discussions with Enterprise Products
Partners Regarding Potential Combination
and Related
Matters
On April 29, 2009, we announced that we
received a proposal on March 9, 2009 from Enterprise Products Partners to
acquire all of our outstanding partnership interests (the “Proposed
Merger”). The proposed consideration for our Units consisted of 1.043
Enterprise Products Partners common units and $1.00 in cash for each of our
Units. In order to evaluate the Proposed Merger, our ACG Committee
formed a special committee consisting of Donald H. Daigle, Irvin Toole, Jr. and
Duke R. Ligon (the “Special Committee”). After considering Enterprise
Products Partners’ proposal with the assistance of its financial and legal
advisors, the Special Committee unanimously concluded that it did not support
the proposal and advised Enterprise Products Partners of its
decision. The Special Committee informed Enterprise Products Partners
that it remained willing to consider a revised proposal.
The general partners of both us and
Enterprise Products Partners are owned by Enterprise GP Holdings, which also
owns approximately 4.2% and 3.0%, respectively, of the outstanding limited
partner units of us and Enterprise Products Partners.
We do not intend to comment further on
discussions with Enterprise Products Partners unless and until a definitive
agreement is reached and we give no assurance that any such agreement will be
executed or that any transaction will be approved or consummated.
For
information regarding lawsuits filed in connection with the Proposed Merger,
please see Part II, Item 1 – Legal Proceedings in this Quarterly
Report.
TEPPCO
Exits Texas Offshore Port System Partnership
In April 2009, we announced that our
affiliate elected to dissociate, or exit from, the Texas Offshore Port System
partnership and forfeit our investment and one-third ownership interest in the
partnership. An affiliate of Enterprise Products Partners also
elected to dissociate from the Texas Offshore Port System partnership at the
same time. As a result, we expect to record a non-cash charge of
approximately $34.2 million against our earnings for the second quarter of
2009. For additional information, see Note 17 in the Notes to
Unaudited Condensed Consolidated Financial Statements included under Item 1 of
this Quarterly Report.
Results
of Operations
The
following table summarizes financial information by business segment for the
periods indicated (in millions):
|
For
the Three Months
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Operating
revenues:
|
||||||||
|
Downstream
Segment
|
$ | 95.5 | $ | 97.7 | ||||
|
Upstream
Segment
|
1,296.2 | 2,655.3 | ||||||
|
Midstream
Segment
|
29.0 | 30.1 | ||||||
|
Marine
Services Segment
|
36.9 | 25.5 | ||||||
|
Intersegment
eliminations
|
-- | (0.1 | ) | |||||
|
Total
operating revenues
|
1,457.6 | 2,808.5 | ||||||
|
Operating
income:
|
||||||||
|
Downstream
Segment
|
34.4 | 36.3 | ||||||
|
Upstream
Segment
|
40.9 | 29.3 | ||||||
|
Midstream
Segment
|
4.5 | 8.4 | ||||||
|
Marine
Services Segment
|
5.2 | 6.6 | ||||||
|
Intersegment
eliminations
|
0.7 | 2.9 | ||||||
|
Total
operating income
|
85.7 | 83.5 | ||||||
|
Equity
in earnings (losses) of unconsolidated affiliates:
|
||||||||
|
Downstream
Segment
|
(3.1 | ) | (4.1 | ) | ||||
|
Upstream
Segment
|
3.3 | 3.0 | ||||||
|
Midstream
Segment
|
25.6 | 23.7 | ||||||
|
Intersegment
eliminations
|
(0.7 | ) | (2.9 | ) | ||||
|
Total
equity in earnings of unconsolidated affiliates
|
25.1 | 19.7 | ||||||
|
Earnings
before interest: (1)
|
||||||||
|
Downstream
Segment
|
31.6 | 32.4 | ||||||
|
Upstream
Segment
|
44.2 | 32.3 | ||||||
|
Midstream
Segment
|
30.1 | 32.2 | ||||||
|
Marine
Services Segment
|
5.2 | 6.6 | ||||||
|
Interest
expense
|
(32.1 | ) | (38.6 | ) | ||||
|
Income
before provision for income taxes
|
79.0 | 64.9 | ||||||
|
Provision
for income taxes
|
0.8 | 0.8 | ||||||
|
Net
income
|
$ | 78.2 | $ | 64.1 | ||||
|
(1)
See
Note 11 in the Notes to Unaudited Condensed Consolidated Financial
Statements for a reconciliation of earnings before interest to net
income.
|
||||||||
Below is
an analysis of the results of operations, including reasons for material changes
in results, by each of our business segments.
Downstream
Segment
The
following table provides financial information for the Downstream Segment for
the periods indicated (in millions):
|
For
the Three Months
|
||||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Operating
revenues:
|
||||||||||||
|
Sales
of petroleum products
|
$ | 6.7 | $ | 7.0 | $ | (0.3 | ) | |||||
|
Transportation
– Refined products
|
35.9 | 37.3 | (1.4 | ) | ||||||||
|
Transportation
– LPGs
|
38.3 | 36.2 | 2.1 | |||||||||
|
Other
|
14.6 | 17.2 | (2.6 | ) | ||||||||
|
Total
operating revenues
|
95.5 | 97.7 | (2.2 | ) | ||||||||
|
Costs
and expenses:
|
||||||||||||
|
Purchases
of petroleum products
|
6.6 | 6.9 | (0.3 | ) | ||||||||
|
Operating
expense
|
24.9 | 26.9 | (2.0 | ) | ||||||||
|
Operating
fuel and power
|
11.0 | 10.5 | 0.5 | |||||||||
|
General
and administrative
|
3.7 | 3.7 | -- | |||||||||
|
Depreciation
and amortization
|
11.5 | 10.2 | 1.3 | |||||||||
|
Taxes
– other than income taxes
|
3.4 | 3.2 | 0.2 | |||||||||
|
Total
costs and expenses
|
61.1 | 61.4 | (0.3 | ) | ||||||||
|
Operating
income
|
34.4 | 36.3 | (1.9 | ) | ||||||||
|
Equity
in losses of unconsolidated affiliates
|
(3.1 | ) | (4.1 | ) | 1.0 | |||||||
|
Other,
net
|
0.3 | 0.2 | 0.1 | |||||||||
|
Earnings
before interest
|
$ | 31.6 | $ | 32.4 | $ | (0.8 | ) | |||||
The
following table presents volumes delivered in barrels and average tariff per
barrel for the periods indicated (in millions, except tariff
information):
|
For
the Three Months
|
Percentage
|
|||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Volumes
Delivered:
|
||||||||||||
|
Refined
products
|
36.6 | 38.5 |
(5%)
|
|||||||||
|
LPGs
|
12.6 | 12.9 |
(2%)
|
|||||||||
|
Total
|
49.2 | 51.4 |
(4%)
|
|||||||||
|
Average
Tariff per Barrel:
|
||||||||||||
|
Refined
products
|
$ | 0.98 | $ | 0.97 |
1%
|
|||||||
|
LPGs
|
3.05 | 2.81 |
9%
|
|||||||||
|
Average
system tariff per barrel
|
1.51 | 1.43 |
6%
|
|||||||||
Three
Months Ended March 31, 2009 Compared with Three Months Ended March 31,
2008
Sales and
purchases related to petroleum products marketing activities at our Aberdeen and
Boligee terminals decreased $0.3 million each for the three months ended March
31, 2009, compared with the three months ended March 31, 2008. The
decreases in purchases and sales were primarily a result of lower fuel prices in
the 2009 period compared to the prior year period, partially offset by the
start-up of the Boligee terminal in August 2008.
Revenues
from refined products transportation decreased $1.4 million for the three months
ended March 31, 2009, compared with the three months ended March 31, 2008,
primarily due to a 5% decrease in refined products volumes delivered, partially
offset by a 1% increase in the average tariff per barrel. Volume
decreases were primarily due to lower long-haul jet fuel and diesel movements
resulting from a decline in product demand, partially offset by higher long-haul
motor fuel and blendstock movements due to higher demand in the Midwest and East
Texas markets resulting from refineries in those areas undergoing
maintenance. The refined products average tariff per barrel increased
primarily due to increases in system tariffs that went into effect in April and
July 2008.
Revenues
from LPG transportation increased $2.1 million for the three months ended March
31, 2009, compared with the three months ended March 31, 2008, primarily due to
a 9% increase in the LPG average tariff per barrel, partially offset by a 2%
decrease in the LPG volumes delivered. The LPGs average rate per
barrel increased from the prior year period, primarily due to increases in
system tariffs that went into effect in July 2008, increased isobutane
deliveries in the Midwest and lower propane deliveries to a Midwest
petrochemical plant that has a lower tariff, resulting from unexpected downtime
of the plant. Propane transportation volumes were slightly lower in
the 2009 period compared to the prior year period primarily due to the
unexpected downtime of the Midwest petrochemical plant during the 2009
period.
Other
operating revenues decreased $2.6 million for the three months ended March 31,
2009, compared with the three months ended March 31, 2008, primarily due to a
$2.2 million decrease in product inventory sales, a $2.1 million decrease in
refined products excess inventory revenue and a $0.9 million decrease in refined
products terminaling revenue, partially offset by a $0.9 million increase in
refined products storage rental, a $0.8 million increase in LPG rental and
location exchange revenues and a $0.4 million increase in refinery grade
propylene transportation revenue due to higher volumes.
Costs and
expenses decreased $0.3 million for the three months ended March 31, 2009,
compared with the three months ended March 31, 2008. Purchases of
petroleum products, discussed above, decreased $0.3 million, compared with the
prior year period. Operating expenses decreased $2.0 million
primarily due to a $4.1 million increase in product measurement gains, a
$0.7 million decrease in transportation expense related to movements on the
Centennial pipeline and a $0.4 million decrease in insurance
premiums. These decreases in operating expenses were partially offset
by a $1.1 million increase in labor and benefits expense, a $1.0 million
increase in pipeline operating and maintenance costs principally related to
periodic tank maintenance requirements and other repairs and maintenance
expenses on various pipeline segments, a $0.6 million increase in pipeline
inspection and repair costs associated with our integrity management program, a
$0.3 million increase in environmental assessments and remediation costs and a
$0.3 million lower of cost or market (“LCM”) adjustment on inventory (see Note 5
in the Notes to Unaudited Condensed Consolidated Financial
Statements). Operating fuel and power increased $0.5 million, primarily due
to higher power rates in the 2009 period as a result of the increased cost of
fuel and true-ups of power accruals. General and administrative
expenses remained virtually unchanged with $0.5 million in severance expense and
a $0.2 million increase in consulting and contract services, offset by a
$0.6 million decrease in labor and benefits expense. Depreciation
expense increased $1.3 million, primarily due to assets placed into
service. Taxes – other than income taxes increased $0.2 million,
primarily due to true-ups of property tax accruals.
Equity in
losses from our equity investment in Centennial decreased $1.0 million for the
three months ended March 31, 2009, compared with the three months ended March
31, 2008, primarily due to lower operating expenses and improved tariff rates on
slightly reduced transportation volumes. Volumes on Centennial
averaged 118,000 barrels per day during the three months ended March 31, 2009,
compared with 122,000 barrels per day during the three months ended March 31,
2008.
Upstream
Segment
The following table provides financial
information for the Upstream Segment for the periods indicated (in
millions):
|
For
the Three Months
|
||||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Operating
revenues: (1)
|
||||||||||||
|
Sales
of petroleum products (2)
|
$ | 1,271.2 | $ | 2,637.7 | $ | (1,366.5 | ) | |||||
|
Transportation
– Crude oil
|
21.9 | 15.3 | 6.6 | |||||||||
|
Other
|
3.1 | 2.3 | 0.8 | |||||||||
|
Total
operating revenues
|
1,296.2 | 2,655.3 | (1,359.1 | ) | ||||||||
|
Costs
and expenses: (1)
|
||||||||||||
|
Purchases
of petroleum products (2)
|
1,229.6 | 2,602.7 | (1,373.1 | ) | ||||||||
|
Operating
expense
|
14.6 | 13.3 | 1.3 | |||||||||
|
Operating
fuel and power
|
1.8 | 1.7 | 0.1 | |||||||||
|
General
and administrative
|
1.9 | 1.8 | 0.1 | |||||||||
|
Depreciation
and amortization
|
5.6 | 4.8 | 0.8 | |||||||||
|
Taxes
– other than income taxes
|
1.8 | 1.7 | 0.1 | |||||||||
|
Total
costs and expenses
|
1,255.3 | 2,626.0 | (1,370.7 | ) | ||||||||
|
Operating
income
|
40.9 | 29.3 | 11.6 | |||||||||
|
Equity
in earnings of unconsolidated affiliates
|
3.3 | 3.0 | 0.3 | |||||||||
|
Earnings
before interest
|
$ | 44.2 | $ | 32.3 | $ | 11.9 | ||||||
|
(1)
Amounts
in this table are presented after elimination of intercompany
transactions, including sales and purchases of petroleum
products.
(2)
Petroleum
products includes crude oil, lubrication oils and specialty
chemicals.
|
||||||||||||
Information presented in the following
table includes the margin of the Upstream Segment, which is a non-GAAP
(Generally Accepted Accounting Principles) financial measure under the rules of
the Securities and Exchange Commission (“SEC”). We calculate the
margin of the Upstream Segment as revenues generated from the sale of crude and
lubrication oils, and transportation of crude oil, less the related cost of
sales (or purchases) of crude and lubrication oils, in each case prior to the
elimination of intercompany amounts. We believe margin is a more
meaningful measure of financial performance than sales and cost of sales of
crude and lubrication oils due to significant fluctuations in the
period-to-period level of our marketing activities for these products and the
underlying commodity prices. Additionally, our management uses the
non-GAAP measure of margin to evaluate the financial performance of the Upstream
Segment because it excludes expenses that are not directly related to the
marketing activities being evaluated. Margin and volume information
for the three months ended March 31, 2009 and 2008 is presented below (in
millions, except per barrel and per gallon amounts):
|
For
the Three Months
|
Percentage
|
|||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Margins:
(1)
|
||||||||||||
|
Crude
oil marketing
|
$ | 32.2 | $ | 20.3 |
59%
|
|||||||
|
Lubrication
oil sales
|
3.2 | 2.7 |
19%
|
|||||||||
|
Revenues:
(1)
|
||||||||||||
|
Crude
oil transportation
|
20.5 | 23.4 |
(12%)
|
|||||||||
|
Crude
oil terminaling (2)
|
7.6 | 3.9 |
95%
|
|||||||||
|
Total
margin/revenues
|
$ | 63.5 | $ | 50.3 |
26%
|
|||||||
|
Total
barrels/gallons:
|
||||||||||||
|
Crude
oil marketing (barrels) (3)
|
45.4 | 43.0 |
6%
|
|||||||||
|
Lubrication
oil volumes (gallons)
|
5.4 | 3.9 |
38%
|
|||||||||
|
Crude
oil transportation (barrels)
|
29.2 | 27.8 |
5%
|
|||||||||
|
Crude
oil terminaling (barrels)
|
46.8 | 33.1 |
41%
|
|||||||||
|
Margin
per barrel:
|
||||||||||||
|
Lubrication
oil margin (per gallon)
|
$ | 0.603 | $ | 0.695 |
(13%)
|
|||||||
|
Average
tariff per barrel:
|
||||||||||||
|
Crude
oil transportation
|
$ | 0.702 | $ | 0.842 |
(17%)
|
|||||||
|
Crude
oil terminaling
|
0.163 | 0.116 |
41%
|
|||||||||
|
(1)
Amounts
in this table are presented prior to the eliminations of intercompany
sales, revenues and purchases between TEPPCO Crude Oil, LLC
(“TCO”) and TEPPCO Crude Pipeline, LLC (“TCPL”), both of which are
our wholly-owned subsidiaries. TCO is a significant shipper on
TCPL.
(2) Revenues
associated with crude oil terminaling are classified as crude oil
transportation in our statements of consolidated income.
(3)
Reported
quantities exclude inter-region transfers, which are transfers among TCO’s
various geographically managed regions. For the three months ended
March 31, 2008, we previously reported 57.6 million barrels, which
included inter-region transfers.
|
||||||||||||
The following table reconciles the
Upstream Segment margin to operating income using the information presented in
the statements of consolidated income and the Upstream Segment financial
information on the preceding page for the periods indicated (in
millions):
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Sales
of petroleum products
|
$ | 1,271.2 | $ | 2,637.7 | ||||
|
Transportation
– Crude oil
|
21.9 | 15.3 | ||||||
|
Less: Purchases
of petroleum products
|
(1,229.6 | ) | (2,602.7 | ) | ||||
|
Total
margin/revenues
|
63.5 | 50.3 | ||||||
|
Other
operating revenues
|
3.1 | 2.3 | ||||||
|
Net
operating revenues
|
66.6 | 52.6 | ||||||
|
Operating
expense
|
14.6 | 13.3 | ||||||
|
Operating
fuel and power
|
1.8 | 1.7 | ||||||
|
General
and administrative
|
1.9 | 1.8 | ||||||
|
Depreciation
and amortization
|
5.6 | 4.8 | ||||||
|
Taxes
– other than income taxes
|
1.8 | 1.7 | ||||||
|
Operating
income
|
$ | 40.9 | $ | 29.3 | ||||
Three
Months Ended March 31, 2009 Compared with Three Months Ended March 31,
2008
Sales of petroleum products and
purchases of petroleum products decreased $1,366.5 million and $1,373.1 million,
respectively, for the three months ended March 31, 2009, compared with the three
months ended March 31, 2008. Operating income increased $11.6 million
for the three months ended March 31, 2009, compared with the three months ended
March 31, 2008. The decreases in sales and purchases were primarily a
result of a decrease in the price of crude oil. The average New York
Mercantile Exchange (“NYMEX”) price of crude oil was $43.31 per barrel for the
three months ended March 31, 2009,
compared
with $97.82 per barrel for the three months ended March 31,
2008. Increased volumes transported and an increase in the crude oil
marketing margin, partially offset by increased costs and expenses discussed
below, were the primary factors resulting in an increase in operating
income.
Crude oil marketing margin increased
$11.9 million, primarily due to the contango pricing environment during the
three months ended March 31, 2009, increased volumes marketed, contract
amendments in light of the current market conditions and decreased
transportation costs, including decreased fuel costs. Lubrication oil
sales margin increased $0.5 million on higher volumes, primarily due to
increased sales of higher margin specialty chemicals and additional margin
resulting from the acquisition of Quality Petroleum, Inc. (“Quality Petroleum”)
on August 1, 2008. Crude oil transportation revenues (prior to
intercompany eliminations) decreased $2.9 million, primarily due to lower
transportation volumes on our South Texas crude oil gathering system, partially
offset by higher transportation volumes on our Basin and West Texas crude oil
gathering systems. Additionally, decreased transportation revenues on
our South Texas and other systems resulted from movements on lower tariff
segments and from lower prices of crude oil acquired through our pipeline loss
allowance in certain of our pipeline tariffs, which resulted in a 17% decrease
in the average tariff per barrel. Crude oil terminaling volumes and
revenues increased 41% and $3.7 million, respectively, as a result of spot
market demand and the completion of a storage tank in August 2008.
Other operating revenues increased $0.8
million for the three months ended March 31, 2009, compared with the three
months ended March 31, 2008. The increase was primarily due to
revenues from fuel transportation services generated as a result of the Quality
Petroleum acquisition.
Costs
and expenses decreased $1,370.7 million for the three months ended March 31,
2009, compared with the three months ended March 31, 2008. Purchases
of petroleum products, discussed above, decreased $1,373.1 million compared with
the prior year period. Operating expenses increased $1.3 million from
the prior year period, primarily due to a $1.3 million increase in operating
expenses resulting from the acquisition of Quality Petroleum, a $0.8 million
increase in product measurement losses and a $0.5 million increase in labor and
benefits expense, partially offset by a $0.5 million decrease in pipeline
inspection and repair costs associated with our integrity management program, a
$0.5 million decrease in pipeline operating and maintenance expenses, mostly
related to periodic tank maintenance requirements and a $0.3 million increase in
environmental assessment and remediation expense. Operating fuel and
power increased $0.1 million primarily as a result of higher transportation
volumes. General and administrative expenses increased $0.1 million
primarily due to severance expenses. Depreciation and amortization
expense increased $0.8 million primarily due to assets placed into service and
an increase in the amortization of equity awards. Taxes – other than
income taxes increased $0.1 million due to true-ups of other tax
accruals.
Equity in earnings from our investment
in Seaway increased $0.3 million for the three months ended March 31, 2009,
compared with the three months ended March 31, 2008, primarily due to an
increase in long-haul volumes and a decrease in pipeline operating and
maintenance expenses, offset by a decrease in transportation revenues and an
increase in product measurement losses. Long-haul volumes on Seaway
averaged 174,000 barrels per day during the three months ended March 31, 2009,
compared with 166,000 barrels per day during the three months ended March 31,
2008.
Midstream
Segment
The following table provides financial
information for the Midstream Segment for the periods indicated (in
millions):
|
For
the Three Months
|
||||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Operating
revenues:
|
||||||||||||
|
Gathering
– Natural gas
|
$ | 13.6 | $ | 13.4 | $ | 0.2 | ||||||
|
Transportation
– NGLs (1)
|
12.5 | 13.0 | (0.5 | ) | ||||||||
|
Other
|
2.9 | 3.7 | (0.8 | ) | ||||||||
|
Total
operating revenues
|
29.0 | 30.1 | (1.1 | ) | ||||||||
|
Costs
and expenses:
|
||||||||||||
|
Operating
expense
|
8.6 | 5.0 | 3.6 | |||||||||
|
Operating
fuel and power
|
2.6 | 3.7 | (1.1 | ) | ||||||||
|
General
and administrative
|
3.0 | 2.6 | 0.4 | |||||||||
|
Depreciation
and amortization
|
9.5 | 9.6 | (0.1 | ) | ||||||||
|
Taxes
– other than income taxes
|
0.8 | 0.8 | -- | |||||||||
|
Total
costs and expenses
|
24.5 | 21.7 | 2.8 | |||||||||
|
Operating
income
|
4.5 | 8.4 | (3.9 | ) | ||||||||
|
Equity
in earnings of unconsolidated affiliates
|
25.6 | 23.7 | 1.9 | |||||||||
|
Other,
net
|
-- | 0.1 | (0.1 | ) | ||||||||
|
Earnings
before interest
|
$ | 30.1 | $ | 32.2 | $ | (2.1 | ) | |||||
|
(1)
Includes
transportation revenue from Enterprise Products Partners of $3.8 million
and $3.4 million for the three months ended March 31, 2009 and 2008,
respectively.
|
||||||||||||
The
following table presents volume and average rate information for the periods
indicated:
|
For
the Three Months
|
Percentage
|
|||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Gathering
– Natural Gas – Jonah: (1)
|
||||||||||||
|
Bcf
|
194.9 | 167.1 |
17%
|
|||||||||
|
Btu
(in trillions)
|
215.1 | 184.6 |
17%
|
|||||||||
|
Average
fee per Mcf
|
$ | 0.261 | $ | 0.258 |
1%
|
|||||||
|
Average
fee per MMBtu
|
$ | 0.236 | $ | 0.234 |
1%
|
|||||||
|
Gathering
– Natural Gas – Val Verde: (1)
|
||||||||||||
|
Bcf
|
42.8 | 38.2 |
12%
|
|||||||||
|
Btu
(in trillions)
|
38.6 | 34.2 |
13%
|
|||||||||
|
Average
fee per Mcf
|
$ | 0.318 | $ | 0.351 |
(9%)
|
|||||||
|
Average
fee per MMBtu
|
$ | 0.352 | $ | 0.392 |
(10%)
|
|||||||
|
Transportation
and movements – NGLs:
|
||||||||||||
|
Transportation
barrels (in millions)
|
14.1 | 16.6 |
(15%)
|
|||||||||
|
Lease
barrels (in millions) (2)
|
2.8 | 3.0 |
(7%)
|
|||||||||
|
Average
rate per barrel
|
$ | 0.824 | $ | 0.736 |
12%
|
|||||||
|
Natural
Gas Sales:
|
||||||||||||
|
Btu
(in trillions)
|
0.8 | 1.7 |
(53%)
|
|||||||||
|
Average
fee per MMBtu
|
$ | 3.377 | $ | 6.806 |
(50%)
|
|||||||
|
Fractionation
– NGLs:
|
||||||||||||
|
Barrels
(in millions)
|
0.8 | 1.1 |
(27%)
|
|||||||||
|
Average
rate per barrel
|
$ | 1.785 | $ | 1.661 |
7%
|
|||||||
|
(1) The
majority of volumes in Val Verde’s contracts are measured in Bcf, while
the majority of volumes in Jonah’s contracts are measured in
Btu. Both measures are shown for each asset for comparability
purposes.
(2)
Revenues
associated with capacity leases are classified as other operating revenues
in our statements of consolidated income.
|
||||||||||||
Three Months Ended March 31, 2009
Compared with Three Months Ended March 31, 2008
Natural gas gathering revenues from the
Val Verde system increased $0.2 million, and volumes gathered increased 4.6 Bcf
for the three months ended March 31, 2009, compared with the three months ended
March 31, 2008, primarily due to an increase in volumes from a third party
natural gas connection and annual rate escalations, partially offset by lower
production as a result of the natural decline of coal bed methane production in
the fields in which the Val Verde gathering system operates. For the
three months ended March 31, 2009, Val Verde’s gathering volumes averaged 476
MMcf/d, compared with 420 MMcf/d for the three months ended March 31,
2008. Val Verde’s average natural gas gathering fee per Mcf decreased
9%, primarily due to the lower rates on the higher volumes from the third party
natural gas connection and lower gathering volumes, partially offset by the
annual rate escalations.
Revenues from the transportation of
NGLs decreased $0.5 million for the three months ended March 31, 2009, compared
with the three months ended March 31, 2008, primarily due to a decrease in
revenues and volumes on the Panola Pipeline resulting from downtime following a
fire during the first quarter of 2009 at a system origination point in East
Texas owned by a third party, a decrease in revenues and volumes on the Dean
Pipeline and a decrease in the short-haul volumes on the Chaparral
Pipeline. These decreases in revenues and volumes were partially
offset by an increase in the average rate on the Chaparral Pipeline as a result
of transporting a higher percentage of long-haul volumes at a higher tariff rate
on the system.
Other operating revenues decreased $0.8
million for the three months ended March 31, 2009, compared with the three
months ended March 31, 2008, primarily due to a 27% decrease in the volume of
NGLs fractionated. The average rate per barrel for the fractionation
of NGLs increased 7% primarily due to a change in the rate structure in the
fractionation agreement, under which volumes of NGLs are fractionated at a fixed
rate beginning April 2008.
Costs and expenses increased $2.8
million for the three months ended March 31, 2009, compared with the three
months ended March 31, 2008. Operating expenses increased $3.6
million from the prior year period primarily due to a $1.2 million increase in
labor and benefits expense, a $1.0 million increase as a result of higher
product measurement losses, a $0.7 million increase in LCM adjustments and a
$0.6 million increase in pipeline inspection and repair costs associated with
our integrity management program. Operating fuel and power decreased
$1.1 million primarily due to lower power costs on the Chaparral Pipeline as a
result of a decrease in volumes. General and administrative expenses
increased $0.4 million primarily due to $0.5 million of severance expense and a
$0.2 million increase in administrative consulting services and supplies and
expenses, partially offset by a $0.3 million decrease in labor and benefits
expense. Depreciation and amortization expense decreased $0.1 million
primarily due to a decrease in amortization expense on Val Verde as a result of
a decrease in volumes on contracts which are included in intangible assets and
amortized under the units-of-production method, partially offset by an increase
in the amortization of equity awards. Taxes – other than income taxes
remained unchanged period-to-period.
Equity in earnings from our investment
in Jonah increased $1.9 million for the three months ended March 31, 2009,
compared with the three months ended March 31, 2008. Earnings
increased primarily due to an $8.3 million increase in natural gas gathering
revenues and an increase in volumes from the system expansion, partially offset
by a $0.9 million decrease in the margin on natural gas sales, a $2.8 million
decrease in Jonah’s condensate sales, a $1.3 million increase in depreciation
and amortization expense primarily relating to the system expansion and a $1.3
million increase in operating, general and administrative expenses. For the
three months ended March 31, 2009 and 2008, Jonah’s gathering volumes averaged
approximately 2.2 Bcf/d and 1.8 Bcf/d, respectively, and total volumes gathered
increased 27.8 Bcf. For the three months ended March 31, 2009 and
2008, our sharing in the earnings of Jonah was 80.64%.
The decrease in Jonah’s natural gas
sales volumes for the three months ended March 31, 2009, compared with the prior
year period, was primarily a result of certain shippers selling gas themselves,
rather than through Jonah. The decrease in Jonah’s natural gas sales
average fee per MMBtu was primarily a result of lower market prices in the 2009
period.
Marine
Services Segment
The following table provides financial
information for the Marine Services Segment for the periods indicated (in
millions):
|
For
the Three Months
|
||||||||||||
|
Ended
March 31,
|
Increase
|
|||||||||||
|
2009
|
2008
|
(Decrease)
|
||||||||||
|
Operating
revenues:
|
||||||||||||
|
Transportation – inland
|
$ | 33.6 | $ | 20.7 | $ | 12.9 | ||||||
|
Transportation – offshore
|
3.3 | 4.8 | (1.5 | ) | ||||||||
|
Total Transportation – Marine
|
36.9 | 25.5 | 11.4 | |||||||||
|
Costs
and expenses:
|
||||||||||||
|
Operating expense
|
18.7 | 8.6 | 10.1 | |||||||||
|
Operating fuel and power
|
4.3 | 5.5 | (1.2 | ) | ||||||||
|
General and administrative
|
1.4 | 0.7 | 0.7 | |||||||||
|
Depreciation and amortization
|
6.4 | 3.7 | 2.7 | |||||||||
|
Taxes – other than income taxes
|
0.9 | 0.4 | 0.5 | |||||||||
|
Total costs and expenses
|
31.7 | 18.9 | 12.8 | |||||||||
|
Operating income
|
5.2 | 6.6 | (1.4 | ) | ||||||||
|
Earnings before interest
|
$ | 5.2 | $ | 6.6 | $ | (1.4 | ) | |||||
Information presented in the following
table includes gross margin and average daily rate for our Marine Services
Segment, which are non-GAAP financial measures under the rules of the
SEC. We calculate gross margin as marine transportation revenues less
operating expense and operating fuel and power. Average daily rate is
calculated as gross margin for the Marine Services Segment divided by fleet
operating days. We believe these non-GAAP measures of gross margin and
average daily rate are meaningful measures of the financial performance of our
Marine Services Segment, in which we provide services under different types of
contracts with varying arrangements for the payment of fuel costs and other
operational fees. These non-GAAP measures allow for comparability of
results across different contracts within a given period, as well as between
periods. Further, our management uses these non-GAAP measures to assist
them in evaluating results of the Marine Services Segment and making decisions
regarding the use and deployment of our marine vessels.
The
following table provides operating statistics for the Marine Services Segment
for the periods indicated:
|
For
the Three Months
Ended
March 31,
|
||||||
|
2009
|
2008
|
|||||
|
Number
of inland tow boats
|
45
|
43
|
||||
|
Number
of inland tank barges
|
105
|
98
|
||||
|
Number
of offshore tow boats
|
6
|
6
|
||||
|
Number
of offshore tank barges
|
8
|
8
|
||||
|
Fleet
available days (in thousands) (1)
|
13.9
|
7.4
|
||||
|
Fleet
operating days (in thousands) (2)
|
12.4
|
6.9
|
||||
|
Fleet
utilization (3)
|
89%
|
93%
|
||||
|
Gross
margin (in millions)
|
$ 13.9
|
$ 11.4
|
||||
|
Average
daily rate (in thousands) (4)
|
$ 1.12
|
$ 1.66
|
||||
|
(1) Equal
to the number of calendar days in the period (for 2008 period, number of
calendar days from our acquisition of Cenac Towing Co., Inc. and
Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of
Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”)
on February 1, 2008 and Horizon Maritime, LLC (“Horizon”) on February 29,
2008 through March 31, 2008) multiplied by the total number of vessels
less the aggregate number of days that our vessels are not operating due
to scheduled maintenance and repairs or unscheduled instances where
vessels may have to be drydocked in the event of accidents and other
unforeseen damage.
(2)
Equal
to the number of our fleet available days in the period (for 2008 period,
number of our fleet available days from our acquisition of Cenac on
February 1, 2008 and Horizon on February 29, 2008 through March 31, 2008)
less the aggregate number of days that our vessels are
off-hire.
(3)
Equal
to the number of fleet operating days divided by the number of fleet
available days during the period.
(4)
Equal
to gross margin divided by the number of fleet operating days during the
period.
|
||||||
The
following table reconciles gross margin to operating income using the
information presented in the statements of consolidated income and the Marine
Services Segment financial information on the preceding page for the periods
indicated (in millions):
|
For
the Three Months
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Transportation
revenue – Marine
|
$ | 36.9 | $ | 25.5 | ||||
|
Less: Operating
expense
|
(18.7 | ) | (8.6 | ) | ||||
|
Less: Operating
fuel and power
|
(4.3 | ) | (5.5 | ) | ||||
|
Gross
margin
|
13.9 | 11.4 | ||||||
|
General
and administrative
|
1.4 | 0.7 | ||||||
|
Depreciation
and amortization
|
6.4 | 3.7 | ||||||
|
Taxes
– other than income taxes
|
0.9 | 0.4 | ||||||
|
Operating
income
|
$ | 5.2 | $ | 6.6 | ||||
Three Months Ended March 31, 2009
Compared with Three Months Ended March 31, 2008
We acquired Cenac and Horizon on
February 1, 2008 and February 29, 2008, respectively. Our ownership
and operation of these assets for only a portion of the three months ended March
31, 2008, as compared to the full three months ended March 31, 2009, accounted
for a substantial portion of the changes in the results of operations in this
segment.
Revenues are primarily influenced by
rates on term contracts along with industry demand, utilization rates of tank
barges and reimbursements of costs of fuel and other specified operational fees
that are recovered under most of the transportation
contracts. Revenues from marine transportation increased $11.4
million for the three months ended March 31, 2009, compared with the three
months ended March 31, 2008, primarily due to the timing of the acquisitions in
the 2008 period as discussed above, partially offset by lower fleet utilization
and decreased reimbursements for the cost of fuel and other specified
operational fees, which are reimbursed by customers and included in inland and
offshore transportation service revenue. These reimbursable revenues
decreased primarily due to a decrease in the price of diesel fuel, as discussed
below in operating fuel and power costs. Fleet utilization decreased
from 93% to 89% for the three months ended March 31, 2009, compared with the
three months ended March 31, 2008, primarily due to reduced demand for barge
services as a result of general economic conditions in the industry, which has
resulted in some inland customer contracts not being renewed during the fourth
quarter of 2008. Most of the marine vessels impacted by these
non-renewals are employed in the spot market until we can secure term
contracts.
Gross
margin and the average daily rate are influenced by rates on term and spot
contracts and renewal of term contracts along with industry
demand. Operating expenses, such as vessel personnel salaries and
related employee benefits and tow boat and tank barge maintenance expenses, also
impact gross margin and average daily rate. Gross margin increased
$2.5 million, while the average daily rate decreased 33% for the three months
ended March 31, 2009, compared with the three months ended March 31, 2008,
primarily due to the ownership and operation of the Cenac and Horizon assets for
only a portion of the three months ended March 31, 2008, as compared to the full
three months ended March 31, 2009. This increase in gross margin was
partially offset by higher operating costs related to increased vessel
maintenance expense, as discussed below. These increases in operating
expenses and an increase in the fleet operating days resulted in a decrease in
the average daily rate in the 2009 period.
Costs and expenses increased $12.8
million for the three months ended March 31, 2009, compared with the three
months ended March 31, 2008. The largest single impact to costs and
expenses was the timing of the acquisitions in the 2008 period as discussed
above. Operating expenses also increased due to a $1.8 million
increase in tow boat and tank barge maintenance expenses, a $1.0 million
increase in payments under the transitional operating agreement for vessel
personnel salaries, related employee benefits and other expenses and a $0.7
million increase in operating supplies and expenses. Operating fuel
and power decreased due to the decline in the price of diesel
fuel. Under contract terms, substantially all operating fuel and
power consumed is directly reimbursed by the customer. General and
administrative
expense
increased primarily due to higher labor and benefits
expense. Depreciation and amortization expense increased primarily
due to the acquisition of additional tow boats and tank barges in the 2008
period. Taxes – other than income taxes increased primarily due to
higher payroll taxes relating to increased labor costs.
Interest Expense
Interest expense decreased $5.6 million
for the three months ended March 31, 2009, compared with the three months ended
March 31, 2008, primarily due to $8.7 million in interest expense recognized in
the 2008 period upon the redemption of the 7.51% TE Products Senior Notes on
January 28, 2008. Of the $8.7 million of expense, $6.6 million
related to a make-whole premium paid with the redemption of the senior notes,
$1.0 million related to the remaining unamortized interest rate swap loss that
had been deferred as an adjustment to the carrying value of the senior notes and
$1.1 million related to unamortized debt issuance costs on the senior
notes. Additionally, the decrease in interest expense was due to $3.6
million of interest expense in the 2008 period resulting from interest payments
hedged under treasury locks not occurring as forecasted, and a $0.9 million
increase in capitalized interest primarily due to higher construction
work-in-progress balances in the 2009 period as compared to the 2008
period. These decreases in interest expense were partially offset by
higher outstanding borrowings in the 2009 period.
Provision
for Income Taxes
Provision for income taxes is
attributable to our state tax obligations under the Revised Texas Franchise Tax
enacted in May 2006. At March 31, 2009 and December 31, 2008, we had
current tax liabilities of $4.7 million and $3.9 million,
respectively. At March 31, 2009, we had a deferred tax asset of less
than $0.1 million. During each of the three months ended March 31,
2009 and 2008, we recorded an increase in current income tax liabilities of $0.8
million. During the three months ended March 31, 2009, adjustments to
deferred tax assets and liabilities were not material to our consolidated
financial statements. The offsetting net charges to deferred tax
expense and income tax expense are shown on our statements of consolidated
income as provision for income taxes.
Financial
Condition and Liquidity
Liquidity
Outlook
Our primary cash requirements consist
of (i) ordinary course operating uses, such as operating expenses, capital
expenditures to sustain existing operations, interest payments on our
outstanding debt and distributions to our unitholders and General Partner, (ii)
growth expenditures, such as capital expenditures for revenue generating
activities (including Jonah) and acquisitions of new assets or businesses and
(iii) repayment of principal on our long-term debt. Our ordinary
course operating cash requirements for 2009 are expected to be funded through
our cash flows from operating activities. We have no material
long-term debt obligations that mature in 2009, and our revolving credit
facility (“Revolving Credit Facility”) does not mature until 2012. We
expect cash requirements for growth expenditures and long-term debt repayments
will be funded by a combination of several sources, including cash flows from
operating activities, borrowings under credit facilities, joint venture
distributions, the issuance of additional equity and debt securities and the
possible disposition of assets.
Our ability to maintain adequate
liquidity depends on our ability to have continued access to the financial
markets and continue to generate cash from operations, both of which are subject
to a number of factors, including prevailing market conditions, the possibility
of a prolonged economic slowdown and general competitive, legislative,
regulatory and other market factors that are beyond our control.
It is our belief that we will continue
to have adequate liquidity to fund future recurring operating and investing
activities. For a discussion of our liquidity outlook, see “General
Outlook for 2009” within Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations in our Annual Report on Form 10-K
for the year ended December 31, 2008.
Cash
Flows from Operating, Investing and Financing Activities
Cash generated from operations,
distributions from our joint ventures, borrowings under our credit facilities
and debt and equity offerings are our primary sources of
liquidity. From time to time we may dispose of assets, which would
provide an additional source of liquidity. At March 31, 2009, we had
a working capital deficit of $13.9 million, while at December 31, 2008, we had a
working capital surplus of $7.6 million. At March 31, 2009, we had
approximately $355.5 million in available borrowing capacity under our Revolving
Credit Facility. Cash flows for the periods indicated were as follows
(in millions):
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash
provided by (used in):
|
||||||||
|
Operating
activities
|
$ | 156.6 | $ | 58.7 | ||||
|
Investing
activities
|
(113.6 | ) | (436.5 | ) | ||||
|
Financing
activities
|
(40.8 | ) | 377.8 | |||||
Operating
Activities
Net cash flow provided by operating
activities was $156.6 million for the three months ended March 31, 2009 compared
to $58.7 million for the three months ended March 31, 2008. The
following were the principal factors resulting in the $97.9 million increase in
net cash flows provided by operating activities:
|
§
|
Cash
flow from operating activities increased due to the timing of cash
receipts and cash disbursements related to working capital
components.
|
|
§
|
Cash
distributions received from unconsolidated affiliates increased $10.5
million. Distributions received from our equity investment in Seaway
increased $8.8 million primarily due to the timing of distributions
received in the 2009 period as compared to the 2008
period. Distributions from our equity investment in Jonah
increased $1.7 million primarily due to increased revenues and volumes
generated from completion of the system
expansion.
|
|
§
|
Cash
paid for interest, net of amounts capitalized, decreased $25.3 million for
the three months ended March 31, 2009 compared with the three months ended
March 31, 2008, primarily due to the redemption of our senior notes in the
2008 period, partially offset by an increase in debt outstanding,
including higher outstanding balances on our variable rate Revolving
Credit Facility. Excluding the effects of hedging activities
and interest capitalized during the year ending December 31, 2009, we
expect interest payments on our fixed rate senior notes and junior
subordinated notes for 2009 to be approximately $139.6
million. We expect to make our interest payments with cash
flows from operating activities.
|
Investing
Activities
Net cash flow used in investing
activities was $113.6 million for the three months ended March 31, 2009 compared
to $436.5 million for the three months ended March 31, 2008. The
following were the principal factors resulting in the $322.9 million decrease in
net cash flows used in investing activities:
|
§
|
Cash
used for business combinations was $338.5 million during the three months
ended March 31, 2008, of which $257.7 million was for the Cenac
acquisition and $80.8 million was for the Horizon
acquisition.
|
|
§
|
Capital
expenditures increased $50.0 million primarily due to higher spending on
revenue generating projects for the three months ended March 31, 2009
compared with the three months ended March 31, 2008. Cash paid
for linefill on assets owned decreased $14.3 million for the three months
ended March 31, 2009 compared with the three months
ended
|
|
|
March
31, 2008, primarily due to the timing of completion of organic growth
projects in our Upstream Segment.
|
|
§
|
Investments
in unconsolidated affiliates decreased $21.2 million, which includes
a $19.5 million decrease in contributions to Jonah primarily related to
lower system expansion spending in 2009 and a $1.7 million decrease in net
contributions to Texas Offshore Port System for the three months ended
March 31, 2009. In January 2009, we received a $3.1 million
refund of our 2008 contributions to Texas Offshore Port System due to a
delay in the timing of the expected project spending. In
February and March 2009, we then invested an additional $1.4 million in
Texas Offshore Port System. See Note 17 in the Notes to
Unaudited Condensed Consolidated Financial Statements for information
regarding our dissociation from the Texas Offshore Port System
partnership.
|
|
§
|
During
the three months ended March 31, 2009 and 2008, we paid $1.4 million and
$0.3 million, respectively, related to the acquisition of intangible
assets.
|
Financing
Activities
Cash flows used in financing activities
totaled $40.8 million for the three months ended March 31, 2009, compared
to cash flows provided by financing activities of $377.8 million for the three
months ended March 31, 2008. The following were the principal factors
resulting in the $418.6 million increase in cash flows used in financing
activities:
|
§
|
During
the three months ended March 31, 2008, we used $1.0 billion of proceeds
from our term credit agreement (i) to fund the cash portion of our Cenac
and Horizon acquisitions, (ii) to fund the redemption of our 7.51% TE
Products Senior Notes in January 2008 and to repay our 6.45% TE Products
Senior Notes, which matured in January 2008, (iii) to repay $63.2 million
of debt assumed in the Cenac acquisition, and (iv) for other general
partnership purposes. We used the proceeds from the issuance of
senior notes in March 2008 to repay the outstanding balance of $1.0
billion under the term credit agreement. Debt issuance costs
paid during the three months ended March 31, 2008 were $8.7
million.
|
|
§
|
Net
borrowings under our Revolving Credit Facility increased $109.8
million.
|
|
§
|
We
paid $52.1 million to settle treasury locks in March 2008 (see Note 4 in
the Notes to Unaudited Condensed Consolidated Financial Statements) upon
the issuance of senior notes.
|
|
§
|
Cash
distributions to our partners increased $16.5 million for the three months
ended March 31, 2009 compared with the three months ended March 31, 2008,
due to an increase in the number of Units outstanding and an increase in
our quarterly cash distribution rate per Unit. We paid cash
distributions of $91.4 million ($0.725 per Unit) and $74.9 million ($0.695
per Unit) during the three months ended March 31, 2009 and 2008,
respectively. Additionally, we declared a cash distribution of
$0.725 per Unit for the quarter ended March 31, 2009. We paid
the distribution of $91.4 million on May 7, 2009 to unitholders of record
on April 30, 2009.
|
|
§
|
Net
proceeds from the issuance of Units to employees under the employee unit
purchase plan (“EUPP”) and the issuance of Units in connection
with our distribution reinvestment plan (“DRIP”) were $1.6 million for the
three months ended March 31, 2009, compared to $2.7 million for the three
months ended March 31, 2008.
|
Other
Considerations
Registration
Statements
We have a universal shelf registration
statement on file with the SEC that allows us to issue an unlimited amount of
debt and equity securities.
We also
have a registration statement on file with the SEC authorizing the issuance of
up to 10,000,000 Units in connection with our DRIP. During the three
months ended March 31, 2009, 63,048 Units have been issued under this
registration statement, generating $1.4 million in net proceeds that we used for
general partnership purposes.
In
addition, we have a registration statement on file related to our EUPP, under
which we can issue up to 1,000,000 Units. During the three months
ended March 31, 2009, 7,507 Units have been issued to employees under this
plan, generating $0.2 million in net proceeds that we used for general
partnership purposes.
For
information regarding our Partnership’s capital, see Note 10 in the Notes to
Unaudited Condensed Consolidated Financial Statements included under Item 1 of
this Quarterly Report.
Debt
Obligations
Except
for routine fluctuations in our unsecured Revolving Credit Facility, there have
been no material changes in the terms of our debt obligations since those
reported in our Annual Report on Form 10-K for the year ended December 31,
2008.
During
September 2008, Lehman Brothers Bank, FSB (“Lehman”), which had a 4.05%
participation in our Revolving Credit Facility, stopped funding its commitment
following the bankruptcy filing of its parent. Assuming that future
fundings are not received for the Lehman percentage commitment, aggregate
available capacity would be reduced by approximately $28.9 million. Our
available borrowing capacity under the facility was approximately $355.5 million
at March 31, 2009.
We were
in compliance with the covenants of our long-term debt obligations at March 31,
2009.
For
information regarding our debt obligations, see Note 9 in the Notes to Unaudited
Condensed Consolidated Financial Statements included under Item 1 of this
Quarterly Report.
Future
Capital Needs and Commitments
We estimate that capital expenditures,
excluding acquisitions and joint venture contributions, for 2009 will be in the
range of $320.0 million to $370.0 million (including approximately $19.0 million
of capitalized interest). Excluding capitalized interest, we expect
to spend in the range of $250.0 million to $300.0 million for revenue generating
projects, which includes $170.0 million for our expected spending on the Motiva
Enterprises, LLC project. We expect to spend approximately $47.0
million to sustain existing operations (including $16.0 million for pipeline
integrity) including life-cycle replacements for equipment at various facilities
and pipeline and tank replacements among all of our business
segments. We expect to spend approximately $4.0 million to improve
operational efficiencies and reduce costs among all of our business
segments.
Additionally, we expect to invest
approximately $28.0 million in our Jonah joint venture during 2009 for the
completion of additional facilities to expand the Pinedale field
production. We do not expect to make further investments in the Texas
Offshore Port System partnership due to our exit from the partnership (see Note
17 in the Notes to Unaudited Condensed Consolidated Financial
Statements).
During 2009, TE Products may be
required to contribute cash to Centennial to cover capital expenditures, debt
service requirements or other operating needs. We continually review
and evaluate
potential
capital improvements and expansions that would be complementary to our present
business operations. These expenditures can vary greatly depending on
the magnitude of our transactions. We may finance capital
expenditures through internally generated funds, joint venture distributions,
debt or the issuance of additional equity, and the possible disposition of
assets.
Off-Balance
Sheet Arrangements
There
have been no material changes with regards to our off-balance sheet arrangements
since those reported in our Annual Report on Form 10-K for the year ended
December 31, 2008.
Contractual
Obligations
Scheduled
maturities of long-term debt. With the exception of routine
fluctuations in the balance of our Revolving Credit Facility, there have been no
material changes in our scheduled maturities of long-term debt since those
reported in our Annual Report on Form 10-K for the year ended December 31,
2008.
Operating
lease obligations. Lease and rental
expense was $4.5 million and $5.4 million during the three months ended March
31, 2009 and 2008, respectively. There have been no material changes
in our operating lease commitments since December 31, 2008.
Purchase
obligations. Apart from that
discussed below, there have been no material changes in our purchase obligations
since December 31, 2008.
Due to our exit from the Texas Offshore
Port System partnership, our capital expenditure commitments decreased by an
estimated $68.0 million. See Note 17 in the Notes to Unaudited
Condensed Consolidated Financial Statements for additional information regarding
this subsequent event.
Summary
of Related Party Transactions
The following table summarizes related
party transactions for the periods indicated (in millions):
|
For
the Three Months
Ended
March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Revenues
from EPCO and affiliates:
|
||||||||
|
Sales
of petroleum products
|
$ | 0.1 | $ | 0.6 | ||||
|
Transportation
– NGLs
|
3.8 | 3.4 | ||||||
|
Transportation
– LPGs
|
4.9 | 2.3 | ||||||
|
Other
operating revenues
|
14.0 | 0.4 | ||||||
|
Related
party revenues
|
$ | 22.8 | $ | 6.7 | ||||
|
Costs
and Expenses from EPCO and affiliates:
|
||||||||
|
Purchases
of petroleum products
|
$ | 26.7 | $ | 19.7 | ||||
|
Operating
expense
|
28.6 | 26.1 | ||||||
|
General
and administrative
|
8.1 | 8.5 | ||||||
|
Costs
and Expenses from unconsolidated affiliates:
|
||||||||
|
Purchases
of petroleum products
|
(0.7 | ) | 1.6 | |||||
|
Operating
expense
|
1.6 | 2.3 | ||||||
|
Costs and Expenses from Cenac
and affiliates:
|
||||||||
|
Operating
expense
|
13.4 | 7.4 | ||||||
|
General
and administrative
|
1.1 | 0.5 | ||||||
|
Related
party expenses
|
$ | 78.8 | $ | 66.1 | ||||
For additional information regarding
our related party transactions, see Note 12 in the Notes to Unaudited Condensed
Consolidated Financial Statements.
Credit
Ratings
Our debt securities are rated BBB- by
Standard & Poor’s Ratings Group (“S&P”), Baa3 by Moody’s Investors
Service, Inc. (“Moody’s”) and BBB- by Fitch Ratings, all with stable
outlooks. Such ratings reflect only the view of the rating agency and
should not be interpreted as a recommendation to buy, sell or hold our
securities. These ratings may be revised or withdrawn at any time by
the agencies at their discretion and should be evaluated independently of any
other rating. Based upon the characteristics of the fixed/floating
unsecured junior subordinated notes that we issued in May 2007, Moody’s and
S&P each assigned 50% equity treatment to these notes. Fitch
Ratings assigned 75% equity treatment to these notes.
Recent
Accounting Pronouncements
The
accounting standard setting bodies have recently issued the following accounting
guidance since those reported in our Annual Report on Form 10-K for the year
ended December 31, 2008 that will or may affect our future financial
statements:
|
§
|
FSP
FAS 157-4, Determining
Fair Value When the Volume and Level of Activity for the Asset or
Liability Have Significantly Decreased and Identifying Transactions That
Are Not Orderly; and
|
|
§
|
FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments. |
For
additional information regarding recent accounting developments, see Note 2 in
the Notes to Unaudited Condensed Consolidated Financial Statements included
under Item 1 of this Quarterly Report.
In the
course of our normal business operations, we are exposed to certain risks,
including changes in interest rates and commodity prices. In order to
manage risks associated with certain identifiable and anticipated transactions,
we use derivative instruments. Derivatives are financial instruments whose
fair value is determined by changes in a specified benchmark such as interest
rates or commodity prices. Typical derivative instruments include futures,
forward contracts, swaps and other instruments with similar
characteristics. Substantially all of our derivatives are used for
non-trading activities. See Note 4 in the Notes to Unaudited
Condensed Consolidated Financial Statements included under Item 1 of this
Quarterly Report for additional information regarding our derivative instruments
and hedging activities.
Our exposures to market risk have not
changed materially since those reported under Part II, Item 7A.
Quantitative and Qualitative Disclosures About Market Risk of our Annual Report
on Form 10-K for the year ended December 31, 2008.
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 debt agreements. This strategy is
a component in controlling our cost of capital associated with such
borrowings. At March 31, 2009, we had no interest rate derivative
instruments outstanding.
Commodity
Derivative Instruments
We seek to maintain a position that is
substantially balanced between crude oil purchases and related sales and future
delivery obligations. The price of crude oil is subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors that are beyond our control. In order to manage the
price risk associated with crude oil, we enter into commodity derivative
instruments
such as
forwards, basis swaps and futures contracts. The purpose of such
hedging strategy is to either balance our inventory position or to lock in a
profit margin.
The
following table shows the effect of hypothetical price movements on the
estimated fair value (“FV”) of our portfolio at the dates indicated (dollars in
millions):
|
Portfolio
Fair Value at
|
|||||||||
|
Scenario
|
Resulting
Classification
|
March
31,
2009
|
April
20,
2009
|
||||||
|
FV
assuming no change in underlying commodity prices
|
Asset
|
$ | 0.6 | $ | 0.5 | ||||
|
FV
assuming 10% increase in underlying commodity prices
|
Asset
|
0.6 | 0.2 | ||||||
|
FV
assuming 10% decrease in underlying commodity prices
|
Asset
|
0.7 | 0.9 | ||||||
As of the end of the period covered by
this Quarterly Report, our management carried out an evaluation, with the
participation of our principal executive officer (the “CEO”) and our principal
financial officer (the “CFO”), of the effectiveness of our disclosure controls
and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of
1934. Based on that evaluation, as of the end of the period covered
by this Quarterly Report, the CEO and CFO concluded:
|
(i)
|
that
our disclosure controls and procedures are designed to ensure that
information required to be disclosed by us in the reports that we file or
submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and communicated
to our management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure;
and
|
|
(ii)
|
that
our disclosure controls and procedures are effective at a reasonable
assurance level.
|
Changes
in Internal Control over Financial Reporting
Other than as discussed under “TEPPCO
Marine Services Transactions” below, there were no changes in our internal
controls over financial reporting (as defined in Rule 13a-15(f) under the
Securities Exchange Act of 1934) or in other factors during the first quarter of
2009, that have materially affected, or are reasonably likely to materially
affect, our internal controls over financial reporting.
TEPPCO
Marine Services Transactions
On February 1, 2008, we acquired
transportation assets and certain intangible assets that comprised the marine
transportation business of Cenac. On February 29, 2008, we purchased
marine assets from Horizon, a privately-held Houston-based company and an
affiliate of Mr. Cenac. These purchases were recorded using purchase
accounting. In recording the TEPPCO Marine Services purchase
transactions, we followed our normal accounting procedures and internal
controls.
The Office of the Chief Accountant of
the SEC has issued guidance regarding the reporting of internal control over
financial reporting in connection with a material acquisition. This
guidance was reiterated in September 2007 to affirm that management may omit an
assessment of an acquired business’ internal control over financial reporting
from management’s assessment of internal control over financial reporting for a
period not to exceed one year. We excluded the operations acquired
from Cenac and Horizon from the scope of our Sarbanes-Oxley Section 404 report
on internal control over financial reporting for the year ended December 31,
2008. We expect to complete the implementation of our internal
control structure over the operations we acquired from Cenac and Horizon in
2009.
The certifications of our General
Partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley
Act of 2002 have been included as exhibits to this Quarterly
Report.
We have been, in the ordinary course of
business, a defendant in various lawsuits and a party to various other legal
proceedings, some of which are covered in whole or in part by
insurance. See discussion of legal proceedings in Note 14 in the
Notes to Unaudited Condensed Consolidated Financial Statements under the
headings “– Litigation” and “– Regulatory Matters,” which is incorporated into
this item by reference.
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 Court
of Chancery of New Castle County in the State of Delaware, as putative class
actions on behalf of other unitholders of TEPPCO, concerning a proposal made by
Enterprise Products Partners to our General Partner to acquire by merger our
Units (the “Proposed Merger”). The complaints name as defendants our
General Partner; Enterprise Products Partners and its general partner; EPCO; Dan
L. Duncan; and each of the directors of our General Partner.
The
complaints allege, among other things, that the terms of the Proposed Merger are
grossly unfair to our unitholders, that Mr. Duncan and other defendants who
control us have acted to drive down the price of our Units and that the Proposed
Merger is an attempt to extinguish, without consideration and without adequate
information having been provided to our unitholders to cast a vote with respect
to the Proposed Merger, a separate derivative action that previously had been
filed in September 2006 by Mr. Brinckerhoff concerning proposals made in our
Proxy Statement and other transactions involving us and Enterprise Products
Partners or its affiliates. See Note 14 for additional information
regarding this proceeding. The complaints further allege that the process
through which a special committee of our ACG Committee was appointed to consider
the Proposed Merger is contrary to the spirit and intent of our partnership
agreement and constitutes a breach of the implied covenant of fair
dealing.
The complaints seek relief (i)
enjoining defendants and all persons acting in concert with them from pursuing
the Proposed Merger; (ii) rescinding the Proposed Merger to the extent it is
consummated or awarding rescissory damages in respect thereof; (iii) directing
defendants to account to plaintiffs and the purported class for all damages
suffered or to be suffered by them as a result of defendants’ alleged wrongful
conduct; and (iv) awarding plaintiffs costs of the actions, including fees and
expenses of their attorneys and experts.
Security holders and potential
investors in our securities should carefully consider the risk factor set forth
below and the risk factors set forth in our Annual Report on Form 10-K for the
year ended December 31, 2008 in addition to other information in such report and
in this Quarterly Report. We have identified these risk factors as
important factors that could cause our actual results to differ materially from
those contained in any written or oral forward-looking statements made by
us or on our behalf.
Our prior interest in the
Texas Offshore Port System partnership and dissociation from
the
partnership
in April 2009 could subject us to various liabilities.
The Texas Offshore Port System
partnership was expected to represent an important component of our
Upstream Segment, requiring an estimated $600.0 million in capital contributions
from us through 2011. Effective April 16, 2009, we and an affiliate
of Enterprise Products Partners elected to dissociate, or exit, from the
partnership. In dissociating from the partnership, we forfeited our
investment and one-third ownership interest in the partnership. The
third partner, Oiltanking, has asserted that the dissociation was wrongful and
in breach of the Texas Offshore Port System partnership agreement, citing
provisions of the agreement that, if applicable, would continue to obligate us
to make capital contributions to fund the project and impose additional
liabilities on us.
None.
|
Exhibit
Number
|
Exhibit
|
|
3.1
|
Certificate
of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to
the Registration Statement of TEPPCO Partners, L.P. (Commission File No.
33-32203) and incorporated herein by reference).
|
|
3.2
|
Fourth
Amended and Restated Agreement of Limited Partnership of TEPPCO Partners,
L.P., dated December 8, 2006 (Filed as Exhibit 3 to the Current Report on
Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on
December 13, 2006).
|
|
3.3
|
First
Amendment to Fourth Amended and Restated Partnership Agreement of TEPPCO
Partners, L.P. dated as of December 27, 2007 (Filed as Exhibit 3.1 to
Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No.
1-10403) filed December 28, 2007 and incorporated herein by
reference).
|
|
3.4
|
Amendment
No. 2 to the Fourth Amended and Restated Agreement of Limited Partnership
of TEPPCO Partners, L.P., dated as of November 6, 2008 (Filed as Exhibit
3.5 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the quarter ended September 30, 2008 and incorporated herein by
reference).
|
|
3.5
|
Amended
and Restated Limited Liability Company Agreement of Texas Eastern Products
Pipeline Company, LLC (Filed as Exhibit 3 to the Current Report on Form
8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May
10, 2007 and incorporated herein by reference).
|
|
3.6
|
First
Amendment to the Amended and Restated Limited Liability Company Agreement
of Texas Eastern Products Pipeline Company, LLC, dated as of November 6,
2008 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the quarter ended September 30, 2008 and
incorporated herein by reference).
|
|
4.1
|
Form
of Certificate representing Limited Partner Units (Filed as Exhibit 4.4 to
the Form S-3 of TEPPCO Partners, L.P. filed on September 3, 2008
(Commission File No. 1-10403) and incorporated herein by
reference).
|
|
4.2
|
Indenture
between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company,
Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and
Jonah Gas Gathering Company, as subsidiary guarantors, and First Union
National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as
Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No.
1-10403) dated as of February 20, 2002 and incorporated herein by
reference).
|
|
4.3
|
First
Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE
Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO
Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary
guarantors, and First Union National Bank, NA, as trustee, dated as of
February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners,
L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and
incorporated herein by reference).
|
|
4.4
|
Second
Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners,
L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM,
L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company,
as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company,
L.P., as New Subsidiary Guarantor, and Wachovia Bank, National
Association, formerly known as First Union National Bank, as trustee
(Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the quarter ended June 30, 2002 and incorporated
herein by reference).
|
|
4.5
|
Third
Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products
Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream
Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering
Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National
Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit
4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
for the year ended December 31, 2002 and incorporated herein by
reference).
|
|
4.6
|
Full
Release of Guarantee dated as of July 31, 2006 by Wachovia Bank, National
Association, as trustee, in favor of Jonah Gas Gathering Company (Filed as
Exhibit 4.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No.
1-10403) for the quarter ended September 30, 2006 and incorporated herein
by reference).
|
|
4.7
|
Indenture,
dated as of May 14, 2007, by and among TEPPCO Partners, L.P., as
issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P.,
TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company,
L.P., as subsidiary guarantors, and The Bank of New York Trust Company,
N.A., as trustee (Filed as Exhibit 99.1 to the Current Report on Form 8-K
of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 15,
2007 and incorporated herein by reference).
|
|
4.8
|
First
Supplemental Indenture, dated as of May 18, 2007, by and among TEPPCO
Partners, L.P., as issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde
Gas Gathering Company, L.P., as subsidiary guarantors, and The Bank of New
York Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to the Current
Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403)
filed on May 18, 2007 and incorporated herein by
reference).
|
|
4.9
|
Second
Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO
Partners, L.P., as issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. , Val Verde Gas
Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO
Midstream Companies, LLC, as subsidiary guarantors, and The Bank of New
York Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to the Current
Report on Form 8-K of TE Products Pipeline Company, LLC (Commission File
No. 1-13603) filed on July 6, 2007 and incorporated herein by
reference).
|
|
4.10
|
Fourth
Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO
Partners, L.P., as issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas
Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO
Midstream Companies, LLC, as subsidiary guarantors, and U.S. Bank National
Association, as trustee (Filed as Exhibit 4.3 to the Current Report on
Form 8-K of TE Products Pipeline Company, LLC (Commission File No.
1-13603) filed on July 6, 2007 and incorporated herein by
reference).
|
|
4.11
|
Fifth
Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO
Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC, and Val Verde Gathering Company, L.P., as
subsidiary guarantors, and U.S. Bank National Association, as trustee
(Filed as Exhibit 4.11 to Form 10-Q of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the quarter ended March 31, 2008 and incorporated
herein by reference).
|
|
4.12
|
Sixth
Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO
Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P.,
as subsidiary guarantors, and U.S. Bank National Association, as trustee
(Filed as Exhibit 4.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the quarter ended March 31, 2008 and incorporated
herein by reference).
|
|
4.13
|
Seventh
Supplemental Indenture, dated as of March 27, 2008, by and among TEPPCO
Partners, L.P., as issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P.,
as subsidiary guarantors, and U.S. Bank National Association, as trustee
(Filed as Exhibit 4.13 to Form 10-Q of TEPPCO Partners, L.P. (Commission
File No. 1-10403) for the quarter ended March 31, 2008 and incorporated
herein by reference).
|
|
4.14
|
Replacement
of Capital Covenant, dated May 18, 2007, executed by TEPPCO Partners,
L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P.,
TEPPCO Midstream Companies,
|
| L.P. and Val Verde Gas Gathering Company, L.P. in favor of the covered debt holders described therein (Filed as Exhibit 99.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 18, 2007 and incorporated herein by reference). | |
| 10.1 | Fifth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, |
| 10.2 | LLC,
TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream
Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2009
(Filed as Exhibit 10.1 to Current Report on Form 8-K of Enterprise
Products Partners L.P. (Commission File No. 1-14323) filed on February 5,
2009 and incorporated herein by reference).
Agreement
and Release between William G. Manias and EPCO, Inc. dated January 19,
2009 (Filed as Exhibit 10.1 to Current Report on Form 8-K of TEPPCO
Partners, L.P. (Commission File No. 1-10403) filed on January 23, 2009 and
incorporated herein by reference).
|
| 10.3* | Amendment to Transitional Operating Agreement between Cenac Towing Co., L.L.C., Cenac Offshore, L.L.C., CTCO Benefits Services, L.L.C., Mr. Arlen B. Cenac, Jr., and TEPPCO Marine Services, LLC, effective as of March 5, 2009. |
| 12.1* | Statement of Computation of Ratio of Earnings to Fixed Charges. |
| 31.1* | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended. |
| 31.2* | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended. |
| 32.1** | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| 32.2** | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* Filed
herewith.
** Furnished herewith
pursuant to Item 601(b)-(32) of Regulation S-K.
+ A management contract
or compensation plan or arrangement.
Pursuant to the requirements of
Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized.
| TEPPCO Partners, L.P. |
|
Date: May
11, 2009
|
By: /s/ JERRY
E. THOMPSON
Jerry E. Thompson,
President and Chief Executive Officer of
Texas
Eastern Products Pipeline Company, LLC, General Partner
|
|
Date: May
11, 2009
|
By: /s/ TRACY
E. OHMART
Tracy E. Ohmart,
Acting Chief Financial Officer, Controller, Assistant
Secretary
and
Assistant Treasurer of
Texas
Eastern Products Pipeline Company, LLC, General
Partner
|
Exhibit
10.3
AMENDMENT
TO TRANSITIONAL OPERATING
AGREEMENT
This Amendment to Transitional Operating Agreement (the
“Amendment”) is made and entered into effective as of March 5, 2009, by and
between CENAC
TOWING CO., L.L.C. (successor by way of merger to Cenac Towing
Co., Inc.), (hereinafter referred to as “Cenac Towing”); CENAC OFFSHORE,
L.L.C., a Louisiana limited liability company (“Cenac Offshore”); CTCO BENEFITS
SERVICES, L.L.C., a Louisiana limited liability company (“CTCO”)
(collectively, the “Cenac Companies”); MR. ARLEN B. CENAC,
JR., a resident of Houma, Louisiana and the owner of all of the
Membership and equity interests in the Cenac Companies, (the “Stockholder”); and
together with the Cenac Companies, (the “Operators”); and TEPPCO MARINE
SERVICES, LLC, a Delaware limited liability company, (the
“Owner”).
WHEREAS,
the Owner and the Operators, other than CTCO, entered into a Transitional
Operating Agreement (the “Transitional Operating Agreement”) on February 1, 2008
under which the Operators agreed to provide certain services relating to marine
vessels and related property all as more particularly described in that
Transitional Operating
Agreement;
WHEREAS,
the Owner and the Operators, including CTCO, desire to amend the Transitional
Operating Agreement to make CTCO a party thereto as one of the Operators and as
one of the Cenac
Companies.
NOW
THEREFORE, in consideration of the premises and the mutual benefits to be
derived by each party hereto, the parties hereto agree as
follows:
1
1.
The term
“Cenac Companies” as defined in the Transitional Operating Agreement is hereby
amended to include CTCO as one of the Cenac
Companies.
2.
The term
“Operators” as defined in the Transitional Operating Agreement is hereby amended
to include CTCO as one of the Operators.
3.
All of
the rights, duties and obligations of the Transitional Operating Agreement that
apply to the Cenac Companies and the Operators shall hereinafter also apply to
CTCO which includes, without limitation, that the term “Operator Indemnified
Party” in the Transitional Operating Agreement shall include
CTCO.
4.
Without
impacting the effectiveness of the agreements contained in the Sections 1, 2 and
3 hereof, and merely from an abundance of caution with respect to the intent of
the parties to this Amendment, the provisions of Section 8.2 of the Transitional
Operating Agreement that are applicable to Operators shall apply to CTCO. Owner
shall waive and require its insurers to waive any right of subrogation against
CTCO and shall have CTCO names as an insured or additional insured, as the case
may be, in all policies as required by Section 8.2(b) of the Transitional
Operating Agreement. As soon as possible following the execution
hereof, Owner shall provide to CTCO certificates of insurance evidencing the
insurance coverages for CTCO.
5.
All
terms, conditions and provisions of the Transitional Operating Agreement are
continued in full force and effect and shall remain unaffected and unchanged
except as specifically amended hereby. The Transitional Operating
Agreement, as amended hereby, is hereby ratified and reaffirmed by the parties
hereto who specifically acknowledge the validity and enforceability
thereof.
2
6.
The
amended constitutes the entire agreement of the parties relating to the matters
contained herein, superseding all prior contracts or agreements among the
parties, whether oral or written, relating to the matters contained
herein.
7.
This
Amendment may be executed in any number of counterparts with the same effect as
if all parties had signed the same document. All counterparts shall be construed
together and shall constitute one and the same
instrument.
IN WITNESS
WHEREOF, the Agreement has been duly executed to be effective on the date
first above
written.
|
TEPPCO
MARINE SERVICES, LLC
|
||
|
BY:
|
/s/ Patricia A.
Totten
|
|
|
Name: PATRICIA
A. TOTTEN
|
||
|
Title: Vice
President and General
Counsel
|
|
CENAC
TOWING CO., L.L.C
|
||
|
BY:
|
/s/ Arlen B. Cenac,
Jr.
|
|
|
ARLEN
B. CENAC, JR.
|
||
|
Managing
Member
|
|
CENAC
OFFSHORE, L.L.C.
|
||
|
BY:
|
/s/ Arlen B. Cenac,
Jr.
|
|
|
ARLEN
B. CENAC, JR.
|
||
|
Managing
Member
|
|
CTCO
BENEFITS SERVICES, L.L.C
|
||
|
BY:
|
/s/ Arlen B. Cenac,
Jr.
|
|
|
ARLEN
B. CENAC, JR.
|
||
|
Managing
Member
|
3
|
Exhibit
12.1
|
|||||||||||||||||||||
|
Statement
of Computation of Ratio of Earnings to Fixed Charges
|
|||||||||||||||||||||
|
Three
Months
|
|||||||||||||||||||||
|
Ended
|
|||||||||||||||||||||
|
March
31,
|
|||||||||||||||||||||
|
2005
|
2006
|
2007
|
2008
|
2009
|
|||||||||||||||||
|
Earnings
|
|||||||||||||||||||||
|
Income From Continuing Operations *
|
138,639 | 158,538 | 132,701 | 115,476 | 53,895 | ||||||||||||||||
|
Fixed
Charges
|
|
93,414 | 101,905 | 119,603 | 165,832 | 38,883 | |||||||||||||||
|
Distributed
Income of
|
|||||||||||||||||||||
|
Investments
in Unconsolidated Affiliates
|
37,085 | 63,483 | 122,900 | 146,095 | 47,679 | ||||||||||||||||
|
Capitalized
Interest
|
(6,759 | ) | (10,681 | ) | (11,030 | ) | (19,170 | ) | (5,276 | ) | |||||||||||
|
Total
Earnings
|
262,379 | 313,245 | 364,174 | 408,233 | 135,181 | ||||||||||||||||
|
Fixed
Charges
|
|||||||||||||||||||||
|
Interest
Expense
|
81,861 | 86,171 | 101,223 | 139,988 | 32,124 | ||||||||||||||||
|
Capitalized
Interest
|
6,759 | 10,681 | 11,030 | 19,170 | 5,276 | ||||||||||||||||
|
Rental
Interest Factor
|
4,794 | 5,053 | 7,350 | 6,674 | 1,483 | ||||||||||||||||
|
Total
Fixed Charges
|
93,414 | 101,905 | 119,603 | 165,832 | 38,883 | ||||||||||||||||
|
Ratio: Earnings
/ Fixed Charges
|
2.81 | 3.07 | 3.04 | 2.46 | 3.48 | ||||||||||||||||
|
* Excludes
discontinued operations, gain on sale of assets, provision for income
taxes and equity in earnings
|
|||||||||||||||||||||
|
of
unconsolidated affiliates.
|
|||||||||||||||||||||
Exhibit
31.1
Certification
of Chief Executive Officer pursuant to Rule 13a-14(a) / Rule
15d-14(a),
promulgated
under the Securities Exchange Act of 1934, as amended
I, Jerry
E. Thompson, certify that:
| 1. | I have reviewed this quarterly report on Form 10-Q of TEPPCO Partners, L.P.; |
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s
board of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
| May 11, 2009 | /s/ JERRY E. THOMPSON |
| Jerry E. Thompson | |
| President and Chief Executive Officer | |
| Texas Eastern Products Pipeline Company, LLC, | |
| as General Partner |
Exhibit
31.2
Certification
of Chief Financial Officer pursuant to Rule 13a-14(a) / Rule
15d-14(a),
promulgated
under the Securities Exchange Act of 1934, as amended
I, Tracy
E. Ohmart, certify that:
1. I
have reviewed this quarterly report on Form 10-Q of TEPPCO Partners,
L.P.;
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s
board of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
May
11, 2009
|
/s/ TRACY E.
OHMART
|
|
Tracy
E. Ohmart
|
|
|
Acting
Chief Financial Officer, Controller, Assistant
|
|
|
Treasurer
and Assistant Secretary
|
|
|
Texas
Eastern Products Pipeline Company, LLC,
|
|
|
as
General
Partner
|
Exhibit
32.1
CERTIFICATION
PURSUANT TO
18
U.S.C. SECTION 1350,
AS
ADOPTED PURSUANT TO SECTION 906
OF
THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report
of TEPPCO Partners, L.P. (the “Company”) on Form 10-Q for the quarter ended
March 31, 2009 (the “Report”), as filed with the Securities and Exchange
Commission on the date hereof, I, Jerry E. Thompson, President and Chief
Executive Officer of Texas Eastern Products Pipeline Company, LLC, the general
partner of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted
pursuant to §906 of the Sarbanes-Oxley Act of 2002,
that:
1. The
Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended;
and
2. The
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the
Company.
/s/ JERRY
E. THOMPSON
Jerry E.
Thompson
President
and Chief Executive Officer
Texas
Eastern Products Pipeline Company, LLC, General Partner
May 11,
2009
A signed
original of this written statement required by Section 906 has been provided to
TEPPCO Partners, L.P. and will be retained by TEPPCO Partners, L.P. and
furnished to the Securities and Exchange Commission or its staff upon
request.
Exhibit
32.2
CERTIFICATION
PURSUANT TO
18
U.S.C. SECTION 1350,
AS
ADOPTED PURSUANT TO SECTION 906
OF
THE SARBANES-OXLEY ACT OF 2002
In
connection with the Quarterly Report of TEPPCO Partners, L.P. (the “Company”) on
Form 10-Q for the quarter ended March 31, 2009 (the “Report”), as filed with the
Securities and Exchange Commission on the date hereof, I, Tracy E. Ohmart,
Acting Chief Financial Officer, Controller, Assistant Treasurer and Assistant
Secretary of Texas Eastern Products Pipeline Company, LLC, the general partner
of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to
§906 of the Sarbanes-Oxley Act of 2002,
that:
1. The Report fully
complies with the requirements of section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended; and
2. The information contained in
the Report fairly presents, in all material respects, the financial condition
and results of operations of the
Company.
/s/ TRACY
E. OHMART
Tracy E.
Ohmart
Acting
Chief Financial Officer, Controller, Assistant
Treasurer
and Assistant Secretary
Texas
Eastern Products Pipeline Company, LLC, General Partner
May 11,
2009
A signed
original of this written statement required by Section 906 has been provided to
TEPPCO Partners, L.P. and will be retained by TEPPCO Partners, L.P. and
furnished to the Securities and Exchange Commission or its staff upon
request.