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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
(MARK ONE)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO. 1-11680
GULFTERRA ENERGY PARTNERS, L.P.
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 76-0396023
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
4 GREENWAY PLAZA
HOUSTON, TEXAS 77046
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code: (832) 676-4853
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
The registrant had 59,685,667 common units outstanding as of May 3, 2004.
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PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)
QUARTER ENDED
MARCH 31,
-------------------
2004 2003(1)
-------- --------
Operating revenues.......................................... $220,339 $230,095
-------- --------
Operating expenses
Cost of natural gas and other products.................... 64,427 90,753
Operation and maintenance................................. 48,496 40,644
Depreciation, depletion and amortization.................. 26,223 23,697
Gain on sale of long-lived assets......................... (24) (106)
-------- --------
139,122 154,988
-------- --------
Operating income............................................ 81,217 75,107
Earnings from unconsolidated affiliates..................... 2,208 3,316
Minority interest income (expense).......................... 12 (33)
Other income................................................ 160 383
Interest and debt expense................................... 28,031 34,486
Loss due to write-off of unamortized debt issuance costs.... -- 3,762
-------- --------
Income before cumulative effect of accounting change........ 55,566 40,525
Cumulative effect of accounting change...................... -- 1,690
-------- --------
Net income.................................................. $ 55,566 $ 42,215
======== ========
Income allocation
Series B unitholders...................................... $ -- $ 3,876
======== ========
General partner
Income before cumulative effect of accounting change.... $ 21,129 $ 14,860
Cumulative effect of accounting change.................. -- 17
-------- --------
$ 21,129 $ 14,877
======== ========
Common unitholders
Income before cumulative effect of accounting change.... $ 29,065 $ 17,454
Cumulative effect of accounting change.................. -- 1,340
-------- --------
$ 29,065 $ 18,794
======== ========
Series C unitholders
Income before cumulative effect of accounting change.... $ 5,372 $ 4,335
Cumulative effect of accounting change.................. -- 333
-------- --------
$ 5,372 $ 4,668
======== ========
Basic and diluted earnings per common unit
Income before cumulative effect of accounting change...... $ 0.49 $ 0.40
Cumulative effect of accounting change.................... -- 0.03
-------- --------
Net income................................................ $ 0.49 $ 0.43
======== ========
Basic weighted average number of common units outstanding... 58,946 44,020
======== ========
Diluted weighted average number of common units
outstanding............................................... 59,242 44,104
======== ========
Distributions declared per common unit...................... $ 0.710 $ 0.675
======== ========
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(1) See Note 1, Basis of Presentation and Summary of Significant Accounting
Policies; Revenue Recognition and Cost of Natural Gas and Other Products.
See accompanying notes.
1
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT UNIT AMOUNTS)
(UNAUDITED)
MARCH 31, DECEMBER 31,
2004 2003
--------- ------------
ASSETS
Current assets
Cash and cash equivalents................................. $ 23,257 $ 30,425
Accounts receivable, net.................................. 166,432 154,235
Affiliated note receivable................................ 3,713 3,768
Other current assets...................................... 23,525 20,595
---------- ----------
Total current assets............................... 216,927 209,023
Property, plant, and equipment, net......................... 2,916,484 2,894,492
Intangible assets........................................... 3,309 3,401
Investments in unconsolidated affiliates.................... 190,732 175,747
Other noncurrent assets..................................... 36,564 38,917
---------- ----------
Total assets....................................... $3,364,016 $3,321,580
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities
Accounts payable.......................................... $ 139,857 $ 168,133
Accrued interest.......................................... 33,982 11,199
Current maturities of senior secured term loan............ 3,000 3,000
Other current liabilities................................. 40,702 27,035
---------- ----------
Total current liabilities.......................... 217,541 209,367
Revolving credit facility................................... 387,000 382,000
Senior secured term loan, less current maturities........... 297,000 297,000
Long-term debt.............................................. 1,137,161 1,129,807
Other noncurrent liabilities................................ 41,596 49,043
---------- ----------
Total liabilities.................................. 2,080,298 2,067,217
---------- ----------
Commitments and contingencies
Minority interest........................................... 1,801 1,777
---------- ----------
Partners' capital
Limited partners
Common units; 59,685,667 and 58,404,649 units issued and
outstanding............................................ 930,340 898,072
Series C units; 10,937,500 units issued and
outstanding............................................ 338,297 341,350
General partner........................................... 13,280 13,164
---------- ----------
Total partners' capital............................ 1,281,917 1,252,586
---------- ----------
Total liabilities and partners' capital............ $3,364,016 $3,321,580
========== ==========
See accompanying notes.
2
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
QUARTER ENDED
MARCH 31,
--------------------
2004 2003
-------- ---------
Cash flows from operating activities
Net income................................................ $ 55,566 $ 42,215
Less cumulative effect of accounting change............... -- 1,690
-------- ---------
Income before cumulative effect of accounting change...... 55,566 40,525
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization................ 26,223 23,697
Distributed earnings of unconsolidated affiliates
Earnings from unconsolidated affiliates.............. (2,208) (3,316)
Distributions from unconsolidated affiliates......... 750 4,710
Gain on sale of long-lived assets....................... (24) (106)
Loss due to write-off of unamortized debt issuance
costs................................................. -- 3,762
Amortization of debt issuance costs..................... 1,358 2,092
Other noncash items..................................... 3,036 523
Working capital changes, net of acquisitions and noncash
transactions............................................ (21,241) (443)
-------- ---------
Net cash provided by operating activities.......... 63,460 71,444
-------- ---------
Cash flows from investing activities
Additions to property, plant and equipment................ (47,833) (81,937)
Proceeds from sale and retirement of assets............... 93 3,088
Additions to investments in unconsolidated affiliates..... (5,800) (133)
-------- ---------
Net cash used in investing activities.............. (53,540) (78,982)
-------- ---------
Cash flows from financing activities
Net proceeds from revolving credit facility............... 44,933 98,991
Repayments of revolving credit facility................... (40,000) (119,000)
Repayment of senior secured acquisition term loan......... -- (237,500)
Debt issuance costs for senior secured term loan.......... (57) --
Net proceeds from (debt issuance costs for) issuance of
long-term debt.......................................... (30) 293,277
Net proceeds from conversion of Series F units............ 48,274 --
Distributions to partners................................. (70,529) (52,080)
Contribution from general partner......................... 321 --
-------- ---------
Net cash used in financing activities.............. (17,088) (16,312)
-------- ---------
Decrease in cash and cash equivalents....................... (7,168) (23,850)
Cash and cash equivalents at beginning of period............ 30,425 36,099
-------- ---------
Cash and cash equivalents at end of period.................. $ 23,257 $ 12,249
======== =========
See accompanying notes.
3
GULFTERRA ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS
(IN THOUSANDS)
(UNAUDITED)
COMPREHENSIVE INCOME
QUARTER ENDED
MARCH 31,
--------------------
2004 2003
------- -------
Net income.................................................. $55,566 $42,215
Other comprehensive loss.................................... (4,299) (5,715)
------- -------
Total comprehensive income.................................. $51,267 $36,500
======= =======
ACCUMULATED OTHER COMPREHENSIVE LOSS
MARCH 31, DECEMBER 31,
2004 2003
--------- ------------
Beginning balance........................................... $ (9,027) $ (5,622)
Unrealized mark-to-market losses on cash flow hedges
arising during period.................................. (8,092) (12,924)
Reclassification adjustments for changes in initial value
of derivative instruments to settlement date........... 3,793 10,018
Accumulated other comprehensive loss from investment in
unconsolidated affiliate............................... -- (499)
-------- --------
Ending balance.............................................. $(13,326) $ (9,027)
======== ========
Accumulated other comprehensive loss allocated to:
Common units' interest.................................... $(11,085) $ (7,488)
======== ========
Series C units' interest.................................. $ (2,068) $ (1,409)
======== ========
General partner's interests............................... $ (173) $ (130)
======== ========
See accompanying notes.
4
GULFTERRA ENERGY PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We are a publicly held Delaware master limited partnership (MLP)
established in 1993 for the purpose of providing midstream energy services,
including gathering, transportation, fractionation, storage and other related
activities for producers of natural gas and oil, onshore and offshore in the
Gulf of Mexico. Our sole general partner is GulfTerra Energy Company, L.L.C., a
recently-formed Delaware limited liability company that is owned 50 percent by a
subsidiary of El Paso Corporation and 50 percent by a subsidiary of Enterprise
Products Partners L.P. (Enterprise), a publicly traded MLP.
We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission (SEC).
Because this is an interim period filing presented using a condensed format, it
does not include all of the disclosures required by generally accepted
accounting principles. You should read it along with our 2003 Annual Report on
Form 10-K, as amended, which includes a summary of our significant accounting
policies and other disclosures. The financial statements as of March 31, 2004,
and for the quarters ended March 31, 2004 and 2003, are unaudited. We derived
the balance sheet as of December 31, 2003, from the audited balance sheet filed
in our 2003 Annual Report on Form 10-K, as amended. In our opinion, we have made
all adjustments, all of which are of a normal, recurring nature, to fairly
present our interim period results. Information for interim periods may not
depict the results of operations for the entire year. In addition, prior period
information presented in these financial statements includes reclassifications
which were made to conform to the current period presentation. These
reclassifications have no effect on our previously reported net income or
partners' capital.
With respect to our Texas intrastate pipeline system, which we acquired in
April 2002, we had previously used the pre-acquisition accounting methodology
for the cash settlement of natural gas imbalance receivables, which included the
cash settlement amounts as a component of operating revenues and cost of natural
gas and other products. However, effective January 1, 2004, we have conformed
our accounting for cash settlements on that system to the same method we use to
account for imbalance receivable settlements on our other systems, which method
accounts for these types of cash settlements as an adjustment to cost of natural
gas and other products. We have determined that this revision is not material to
our previously reported financial statements. Accordingly, we have not revised
our previously filed financial statements to reflect this change in methodology.
Unbilled Trade Receivables and Accrued Gas Purchase Costs
As of March 31, 2004 and December 31, 2003, we had included in accounts
receivable, net on our balance sheets, unbilled trade receivables of $73.3
million and $63.1 million. Also, as of March 31, 2004 and December 31, 2003, we
had included in accounts payable on our balance sheets, accrued gas purchase
costs of $16.9 million and $15.4 million.
Allowance for Doubtful Accounts
We have established an allowance for losses on accounts that we believe are
uncollectible. We review collectibility regularly and adjust the allowance as
necessary, primarily under the specific identification method. As of March 31,
2004 and December 31, 2003, our allowance was $4.0 million.
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As generally used in the energy industry and in this document, the following
terms have the following meanings:
/d = per day MBbls = thousand barrels
Bbl = barrel MDth = thousand dekatherms
Bcf = billion cubic feet MMcf = million cubic feet
When we refer to cubic feet measurements, all measurements are at 14.73 pounds per square inch.
5
Revenue Recognition and Cost of Natural Gas and Other Products
Typhoon Oil Pipeline, a wholly owned subsidiary, has transportation
agreements with BHP and ChevronTexaco which provide that Typhoon Oil purchase
the oil produced at the inlet of its pipeline for an index price less an amount
that compensates Typhoon Oil for transportation services. At the outlet of its
pipeline, Typhoon Oil resells this oil back to these producers at the same index
price. As disclosed in our 2003 Annual Report on Form 10-K, as amended, we now
record revenue from these buy/sell transactions upon delivery of the oil based
on the net amount billed to the producers. For the quarter ended March 31, 2003,
we reduced by $48.8 million our revenues and cost of natural gas and other
products to conform to the current period presentation. This revision had no
effect on operating income, net income or partners' capital.
Accounting for Stock-Based Compensation
We use the intrinsic value method established in Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, to value
unit options issued to individuals who are on our general partner's current
board of directors and for those grants made prior to El Paso Corporation's
acquisition of our general partner in August 1998 under our Omnibus Plan and
Director Plan. For the quarters ending March 31, 2004 and 2003, the cost of this
stock-based compensation had no impact on our net income, as all options granted
had an exercise price equal to the market value of the underlying common stock
on the date of grant. We use the provisions of Statement of Financial Accounting
Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, to account
for all of our other stock-based compensation programs.
6
If compensation expense had been determined by applying the fair value
method in SFAS No. 123 to all of our grants, our net income allocated to common
unitholders and net income per common unit would have approximated the pro forma
amounts below:
QUARTER ENDED
MARCH 31,
---------------------
2004 2003
--------- ---------
(IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)
Net income as reported(1)................................... $55,566 $42,215
Less: Additional stock-based employee compensation expense
determined under fair value based method.................. (7) (191)
------- -------
Pro forma net income........................................ $55,559 $42,024
======= =======
Pro forma net income allocated to common unitholders........ $29,058 $18,603
======= =======
Earnings per common unit:
Basic, as reported........................................ $ 0.49 $ 0.43
======= =======
Basic, pro forma.......................................... $ 0.49 $ 0.42
======= =======
Diluted, as reported...................................... $ 0.49 $ 0.43
======= =======
Diluted, pro forma........................................ $ 0.49 $ 0.42
======= =======
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(1) Stock-based employee compensation expense of $134 thousand and $313 thousand
are included in net income for the quarters ended March 31, 2004 and March
31, 2003.
The effects of applying SFAS No. 123 in this pro forma disclosure may not
be indicative of future amounts.
Our remaining accounting policies are consistent with those discussed in
our 2003 Annual Report on Form 10-K, as amended, except as discussed below.
Consolidation of Variable Interest Entities
During the first quarter of 2004, we adopted the provisions of Financial
Accounting Standards Board Interpretation (FIN) No. 46, Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
(ARB) No. 51, as replaced by FIN No. 46-R. This interpretation defines a
variable interest entity (VIE) as a legal entity whose equity owners do not have
sufficient equity at risk and/or a controlling financial interest in the entity
and excludes certain joint ventures of other entities that meet the
characteristics of a business. Our adoption of FIN No. 46 had no effect on our
reported results or financial position.
2. MERGER WITH ENTERPRISE
On December 15, 2003, we, along with Enterprise and El Paso Corporation,
announced that we had executed definitive agreements to merge Enterprise and
GulfTerra to form one of the largest publicly traded MLPs.
In April 2004, Enterprise and El Paso Corporation amended their agreement
with respect to the ownership of Enterprise's general partner interest upon the
completion of our merger with Enterprise.
As originally envisioned in the merger agreement, El Paso Corporation was
to contribute its 50-percent ownership interest in our general partner to
Enterprise's general partner, in exchange for a 50-percent ownership interest in
Enterprise's general partner. Under the amended transaction, El Paso Corporation
will still contribute its 50-percent ownership interest in our general partner
to Enterprise's general partner, but in exchange, El Paso Corporation will
receive a 9.9-percent ownership interest in Enterprise's general partner and
7
$370 million in cash. The remaining 90.1-percent ownership interest in
Enterprise's general partner will continue to be owned by affiliates of
privately-held Enterprise Products Company.
The remaining transactions with respect to our merger with Enterprise are
unchanged. These include:
- the payment of $500 million in cash from Enterprise to El Paso
Corporation for approximately 13.8 million units, which include 2.9
million of our common units and all of our Series C units owned by El
Paso Corporation;
- the exchange of 1.81 Enterprise common units for each GulfTerra common
unit owned by GulfTerra's unitholders, including the remaining
approximately 7.5 million GulfTerra common units owned by El Paso
Corporation.
MERGER RELATED COSTS
As a result of the pending merger with Enterprise, we determined that it
was in our and our unitholders' best interest to offer selected employees of El
Paso Corporation incentives to continue to focus on the business of the
partnership during the merger process. We have accounted for these incentives
under the provisions of SFAS No. 146, Accounting for Costs Associated with Exit
or Disposal Activities. As of March 31, 2004, we recorded a liability and a
related deferred charge of $4.3 million, which are reflected in other current
liabilities and other current assets on our balance sheets. Our liability was
estimated based upon the number of employees accepting the offer and the
discounted amount they are expected to be paid. We are amortizing the deferred
asset to expense ratably over the expected period of the services required in
order to qualify for receiving the payments. We expect to amortize the entire
expense by merger close. During the quarter ended March 31, 2004, we had
amortized $0.6 million to expense. If our expectations of future amounts to be
paid or the period of service to be rendered change, we will adjust our
liability.
Additionally, during the first quarter of 2004, we recognized an expense of
$3.5 million associated with a fairness opinion we received on our pending
merger with Enterprise. All of our merger related costs are included in
operation and maintenance expenses on our statements of income and are allocated
across all of our operating segments.
3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
We hold investments in various affiliates which we account for using the
equity method of accounting. Summarized financial information for these
investments are as follows:
QUARTER ENDED MARCH 31, 2004
(IN THOUSANDS)
DEEPWATER CAMERON
COYOTE GATEWAY(1) HIGHWAY(1) POSEIDON TOTAL
------ ---------- ---------- -------- ------
END OF PERIOD OWNERSHIP INTEREST............ 50% 50% 50% 36%
====== ===== ===== =======
OPERATING RESULTS DATA:
Operating revenues........................ $1,800 $ -- $ -- $ 9,275
Other income.............................. 1 5 32 13
Operating expenses........................ (198) (26) -- (1,336)
Depreciation.............................. (360) -- -- (2,109)
Other expenses............................ (171) (214) (127) (881)
------ ----- ----- -------
Net income................................ $1,072 $(235) $ (95) $ 4,962
====== ===== ===== =======
OUR SHARE:
Allocated income (loss)................... $ 536 $(118) $ (48) $ 1,786
Adjustments(2)............................ (2) 32 (9) 61
------ ----- ----- -------
Earnings (loss) from unconsolidated
affiliates............................. $ 534 $ (86) $ (57) $ 1,847 $2,208(3)
====== ===== ===== ======= ======
Allocated distributions................... $ 750 $ -- $ -- $ -- $ 750
====== ===== ===== ======= ======
8
QUARTER ENDED MARCH 31, 2003
(IN THOUSANDS)
DEEPWATER
COYOTE GATEWAY(1) POSEIDON TOTAL
------ ---------- -------- ------
END OF PERIOD OWNERSHIP INTEREST....................... 50% 50% 36%
====== ===== =======
OPERATING RESULTS DATA:
Operating revenues................................... $1,923 $ -- $12,062
Other income......................................... 2 13 21
Operating expenses................................... (121) -- (771)
Depreciation......................................... (339) -- (2,084)
Other expenses....................................... (197) (5) (1,475)
------ ----- -------
Net income........................................... $1,268 $ 8 $ 7,753
====== ===== =======
OUR SHARE:
Allocated income..................................... $ 634 $ 4 $ 2,791
Adjustments(2)....................................... (5) (4) (104)
------ ----- -------
Earnings from unconsolidated affiliate............... $ 629 $ -- $ 2,687 $3,316
====== ===== ======= ======
Allocated distributions.............................. $ 750 $ -- $ 3,960 $4,710
====== ===== ======= ======
- ----------
(1) Cameron Highway Oil Pipeline Company and Deepwater Gateway, L.L.C. are
development stage companies; therefore there are no operating revenues or
operating expenses. Since their formations in June 2003 and June 2002, they
have incurred organizational expenses and received interest income.
(2) We recorded adjustments primarily for differences from estimated earnings
reported in our Quarterly Report on Form 10-Q and actual earnings reported
in the unaudited financial statements of our unconsolidated affiliates.
(3) Total earnings from unconsolidated affiliates includes a $30 thousand
reduction associated with the true-up of the gain on the sale of our
interest in Copper Eagle.
4. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment consisted of the following:
MARCH 31, DECEMBER 31,
2004 2003
---------- ------------
(IN THOUSANDS)
Property, plant and equipment, at cost(1)
Pipelines................................................. $2,487,102 $2,487,102
Platforms and facilities.................................. 121,105 121,105
Processing plants......................................... 305,904 305,904
Oil and natural gas properties............................ 131,100 131,100
Storage facilities........................................ 337,927 337,535
Construction work-in-progress............................. 431,258 383,640
---------- ----------
3,814,396 3,766,386
Less accumulated depreciation, depletion and amortization... 897,912 871,894
---------- ----------
Total property, plant and equipment, net............... $2,916,484 $2,894,492
========== ==========
- ---------------
(1) Includes leasehold acquisition costs with an unamortized balance of $2.4
million and $3.2 million at March 31, 2004 and December 31, 2003. One
interpretation being considered relative to SFAS No. 141, Business
Combinations, and SFAS No. 142, Goodwill and Intangible Assets, is that oil
and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds should be classified separately from oil and gas
properties, as intangible assets on our consolidated balance sheets. We will
continue to include these costs in property, plant, and equipment until
definitive guidance is provided.
9
5. FINANCING TRANSACTIONS
The close of the merger with Enterprise, announced in December 2003, will
constitute a change of control, and thus a default, under our credit facility,
therefore we will either repay or amend the facility prior to the close. In
addition, the merger close will constitute a change of control under our
indentures, and we will be required to offer to repurchase our outstanding
senior subordinated notes (and possibly our senior notes) at 101 percent of
their principal amount after the close. In coordination with Enterprise, we are
evaluating alternative financing plans in preparation for the close of the
merger. We and Enterprise can agree on the date of the merger close after the
receipt of all necessary approvals. We do not intend to close until appropriate
financing is in place.
CREDIT FACILITY
Our credit facility consists of two parts: the revolving credit facility
maturing in 2006 and a senior secured term loan maturing in 2008. Our credit
facility is guaranteed by us and all of our subsidiaries, except for our
unrestricted subsidiaries, as detailed in Note 12, and is collateralized with
substantially all of our assets (excluding the assets of our unrestricted
subsidiaries). The interest rates we are charged on our credit facility are
determined at our option using one of two indices that include (i) a variable
base rate (equal to the greater of the prime rate as determined by JPMorgan
Chase Bank or the federal funds rate plus 0.5%); or (ii) LIBOR. The interest
rate we are charged is contingent upon our leverage ratio, as defined in our
credit facility, and credit ratings we are assigned by S&P or Moody's. Depending
on the credit ratings on our senior secured credit facility and our leverage
ratio, the interest we are charged varies from 1.00% to 2.75% over LIBOR or
0.00% to 1.75% over the variable base rate discussed above. Additionally, we pay
commitment fees on the unused portion of our revolving credit facility at rates
that vary from 0.30% to 0.50%.
Our credit facility contains covenants that include restrictions on our and
our subsidiaries' ability to incur additional indebtedness or liens, sell
assets, make loans or investments, acquire or be acquired by other companies and
amend some of our contracts, as well as requiring maintenance of certain
financial ratios. Failure to comply with the provisions of any of these
covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries and could restrict our ability to make
distributions to our unitholders. In addition, our failure to comply with the
provisions of any of the covenants could also be a breach of our merger
agreement with Enterprise.
Revolving Credit Facility
At March 31, 2004, we had $387 million outstanding under our revolving
credit facility at an average interest rate of 3.11%. We may elect that all or a
portion of the revolving credit facility bear interest at either the variable
rate described above increased by 1.0% or LIBOR increased by 2.0%. The amount
available to us at March 31, 2004, under this facility was $313 million.
Senior Secured Term Loan
At March 31, 2004, we had $300 million outstanding under our senior secured
term loan with an average interest rate of 3.36%. The senior secured term loan
is payable in semi-annual installments of $1.5 million in June and December of
each year for the first nine installments and the remaining balance at maturity
in December 2008. We may elect that all or a portion of the senior secured term
loan bear interest at either 1.25% over the variable base rate discussed above,
or LIBOR increased by 2.25%.
10
LONG-TERM DEBT
In March 2004, we gave notice to exercise our right, under the terms of our
senior subordinated notes' indentures, to repay, at a premium, approximately
$39.1 million in principal amount of our 8 1/2% senior subordinated notes due
June 2010. We will recognize additional costs totaling $4.1 million resulting
from the payment of the redemption premiums and the write-off of unamortized
debt issuance costs. We will account for these costs as an expense during the
second quarter of 2004 in accordance with the provisions of SFAS No. 145,
Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No.
13, and Technical Corrections.
In April 2004, we initiated a full redemption of all our outstanding $175
million aggregate principal amount of 10 3/8% senior subordinated notes due
2009. The notes will be redeemed on June 1, 2004, at a redemption price of
105.2% of the principal amount, plus accrued and unpaid interest to June 1,
2004. Interest on the notes will cease to accrue on and after June 1, 2004, and
the only remaining right of holders of the notes will be to receive payment of
the redemption price upon surrender to the paying agent, plus accrued and unpaid
interest up to, but not including, June 1, 2004. In connection with the
redemption of the notes, we will recognize additional expense during the second
quarter of 2004 totaling $12.1 million resulting from the payment of the
redemption premium and the write-off of unamortized debt issuance costs.
Our senior and senior subordinated notes include provisions that, among
other things, restrict our ability and the ability of our subsidiaries
(excluding our unrestricted subsidiaries) to incur additional indebtedness or
liens, sell assets, make loans or investments, acquire or be acquired by other
companies, and enter into sale and lease-back transactions, as well as requiring
maintenance of certain financial ratios. Failure to comply with the provisions
of these covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries in addition to restricting our ability
to make distributions to our unitholders. In addition, our failure to comply
with the provisions of any of the covenants could also be a breach of our merger
agreement with Enterprise. Many restrictive covenants associated with our senior
notes will effectively be removed following a period of 90 consecutive days
during which they are rated Baa3 or higher by Moody's or BBB- or higher by S&P,
and some of the more restrictive covenants associated with some (but not all) of
our senior subordinated notes will be suspended should they be similarly rated.
In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million of our 8 1/2% senior subordinated notes
due 2011. With this swap agreement, we paid the counterparty a LIBOR based
interest rate plus a spread of 4.20% and received a fixed rate of 8 1/2%. The
net amount to be paid or received under the interest rate swap contract is added
to or deducted from the interest and debt expense on our senior subordinated
notes for which the swap contract was executed, payable semi-annually in June
and December. In December 2003, we received $2.8 million related to the interest
rate swap contract. We accounted for this derivative as a fair value hedge under
SFAS No. 133. In March 2004, we terminated our fixed to floating interest rate
swap with our counterparty. The value of the transaction at termination was
zero, and as such neither we, nor our counterparty, were required to make any
additional payments. Also, neither we, nor our counterparty, have any future
obligations under this transaction.
INDUSTRIAL REVENUE BONDS
In April 2004, we reduced the sales tax assessable by the State of
Mississippi related to our Petal natural gas storage expansion and pipeline
project completed in September 2002, by completing that project's qualification
for tax incentives available under the Mississippi Business Finance Act (MBFA).
To complete the qualification, Petal Gas Storage, L.L.C. (Petal), our indirect,
wholly-owned subsidiary, borrowed $52 million from the Mississippi Business
Finance Corporation (MBFC) pursuant to a loan agreement between Petal and the
MBFC. On the same date, the MBFC issued $52.0 million in Industrial Development
Revenue Bonds to us. The loan agreement and the Industrial Development Revenue
Bonds have identical interest rates of 6.25% and maturities of fifteen years.
The bonds and tax exemptions are authorized under the
11
MBFA. Petal may repay the loan agreement without penalty, and thus cause the
Industrial Development Revenue Bonds to be redeemed, any time after one year
from their date of issue.
OTHER CREDIT FACILITIES
Poseidon
Poseidon Oil Pipeline Company, L.L.C., an unconsolidated affiliate in which
we have a 36 percent joint venture ownership interest, was party to a $185
million credit agreement, under which it had $123 million outstanding at
December 31, 2003. In January 2004, Poseidon amended its credit agreement and
decreased the availability to $170 million. The amended facility matures in
January 2008. The outstanding balance from the previous facility was transferred
to the new facility. The interest rates Poseidon is charged on balances
outstanding under its credit facility are variable and depend on its ratio of
total debt to earnings before interest, taxes, depreciation and amortization.
This credit agreement is secured by substantially all of Poseidon's assets. As
of March 31, 2004, Poseidon had $119 million outstanding with an average
interest rate of 2.60%.
Poseidon's credit agreement contains covenants such as restrictions on debt
levels, restrictions on liens, restrictions on mergers and on the sales of
assets and dividend restrictions and requirements to maintain certain financial
ratios.
In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of the
$123 million outstanding at 3.49% through January 2004. This interest rate swap
expired on January 9, 2004.
Deepwater Gateway
Deepwater Gateway, our joint venture that is constructing the Marco Polo
tension leg platform (TLP), obtained a $155 million project finance loan from a
group of commercial lenders to finance a substantial portion of the cost to
construct the Marco Polo TLP and related facilities. Interest rates are variable
and the loan is collateralized by substantially all of Deepwater Gateway's
assets. If Deepwater Gateway defaults on its payment obligations under the
project finance loan, we would be required to pay to the lenders all
distributions we or any of our subsidiaries have received from Deepwater Gateway
up to $22.5 million. As of March 31, 2004, Deepwater Gateway had $155 million
outstanding under the project finance loan at an average interest rate of 2.88%
and had not paid us or any of our subsidiaries any distributions.
This project finance loan will mature in July 2004 unless construction is
completed before that time and Deepwater Gateway meets other specified
conditions, in which case the project finance loan will convert into a term loan
with a final maturity date of July 2009.
Cameron Highway
Cameron Highway Oil Pipeline Company, an unconsolidated affiliate in which
we have a 50 percent joint venture ownership interest, entered into a $325
million project loan facility, consisting of a $225 million construction loan
and $100 million of senior secured notes, each of which fund proportionately as
construction costs are incurred.
The construction loan bears interest at a variable rate. Upon completion of
the construction, the construction loan will convert to a term loan maturing
July 2008, subject to the terms of the loan agreement. At the end of the first
quarter following the first anniversary of the conversion into a term loan,
Cameron Highway will be required to make quarterly principal payments of $8.125
million, with the remaining unpaid principal amount payable on the maturity
date. If the construction loan fails to convert into a term loan by December 31,
2006, the construction loan and senior secured notes become fully due and
payable. At March 31, 2004, Cameron Highway has $109 million outstanding under
the construction loan at an average interest rate of 4.18%.
12
The interest rate on Cameron Highway's senior secured notes is 3.25% over
the rate on 10-year U.S. Treasury securities. Principal payments of $4 million
are due quarterly from September 2008 through December 2011, $6 million each
from March 2012 through December 2012, and $5 million each from March 2013
through the principal maturity date of December 2013. At March 31, 2004, Cameron
Highway has $89 million outstanding under the notes at an average interest rate
of 7.29%.
The project loan facility as a whole is secured by (1) substantially all of
Cameron Highway's assets, including, upon conversion, a debt service reserve
capital account, and (2) all of the equity interest in Cameron Highway. Other
than the pledge of our equity interest and our construction obligations under
the relevant producer agreements, the debt is non-recourse to us. The
construction loan and senior secured notes prohibit Cameron Highway from making
distributions to us until the construction loan is converted into a term loan
and Cameron Highway meets certain financial requirements.
DEBT MATURITY TABLE
Aggregate maturities of the principal amounts of long-term debt and other
financing obligations for the remainder of 2004 and the following 4 years and in
total thereafter are as follows at March 31, 2004 (in thousands):
2004........................................................ $ 3,000
2005........................................................ 3,000
2006........................................................ 390,000
2007........................................................ 3,000
2008........................................................ 288,000
Thereafter.................................................. 1,135,600
----------
Total long-term debt and other financing obligations,
including current maturities........................... $1,822,600
==========
6. PARTNERS' CAPITAL
Cash distributions
In February 2004, we paid cash distributions of $0.71 per common and Series
C unit, representing $49.3 million in aggregate. In addition, we paid our
general partner $21.3 million related to its general partner interest. In April
2004, we declared a cash distribution of $0.71 per common unit for the quarter
ended March 31, 2004, which we will pay on May 14, 2004, to holders of record as
of April 30, 2004. Also in May 2004, we will pay our general partner $21.2
million in incentive distributions. At the current distribution rate, our
general partner receives approximately 30.2 percent of our total cash
distributions for its role as our general partner.
13
Series F Convertible Units
In connection with a public offering in May 2003, we issued 80 Series F
convertible units convertible into a maximum of 8,329,679 common units and
comprised of two separate detachable units. The Series F1 units are convertible
into up to $80 million of common units anytime after August 12, 2003, and until
the date we merge with Enterprise (subject to other defined extension rights).
The Series F2 units are convertible into up to $40 million of common units prior
to March 30, 2005 (subject to defined extension rights). The price at which the
Series F convertible units may be converted to common units is equal to the
lesser (i) of the prevailing price (as defined below), if the prevailing price
is equal to or greater than $35.75, or (ii) the prevailing price minus the
product of 50 percent of the positive difference, if any, of $35.75 minus the
prevailing price. The prevailing price is equal to the lesser of (i) the average
closing price of our common units for the 60 business days ending on and
including the fourth business day prior to our receiving notice from the holder
of the Series F convertible units of their intent to convert them into common
units, (ii) the average closing price of our common units for the first seven
business days of the 60 day period included in (i); or (iii) the average closing
price of our common units for the last seven business days of the 60 day period
included in (i). The price at which the Series F convertible units could have
been converted to common units, assuming we had received a conversion notice on
March 31, 2004 and May 3, 2004, was $41.12 and $39.01 per common unit. Holders
of Series F convertible units are not entitled to vote or to receive
distributions. The value of the Series F convertible units was $2.6 million as
of March 31, 2004, and is included in partners' capital as a component of common
units.
In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26 per unit, paying the holder an amount of cash equal
to the market price of the net number of units. These amendments had no effect
on the classification of the Series F convertible units on the balance sheet at
March 31, 2004 and December 31, 2003.
In the first quarter of 2004, 45 Series F1 convertible units were converted
into 1,146,418 common units, for which the holder of the convertible units paid
us $45 million. Additionally, our general partner contributed to us $0.3 million
in cash in order to maintain its one percent general partner interest.
Any Series F1 convertible units for which a conversion notice has not been
delivered prior to the merger closing date, or termination of the merger, will
expire upon the closing, or termination, of the merger with Enterprise. Any
Series F2 convertible units outstanding at the merger date will be converted
into rights to receive Enterprise common units, subject to the restrictions
governing the Series F units. The number of Enterprise common units and the
price per unit at conversion will be adjusted based on the 1.81 exchange ratio.
Option Plans
Total unamortized deferred compensation as of March 31, 2004 and December
31, 2003, was approximately $1.1 million and $1.5 million. Deferred compensation
is reflected as a reduction of partners' capital and is allocated 1 percent to
our general partner and 99 percent to our limited partners. We did not grant any
unit options or restricted units under the Omnibus Plan or the Director Plan
during the quarter ended March 31, 2004.
Net proceeds from unit options exercised during the quarter ended March 31,
2004, was approximately $4.6 million. There were no unit options exercised
during the quarter ended March 31, 2003.
14
7. EARNINGS PER COMMON UNIT
The following table sets forth the computation of basic and diluted
earnings per common unit (in thousands, except per unit amounts):
QUARTER ENDED
MARCH 31,
-----------------
2004 2003
------- -------
Numerator:
Numerator for basic earnings per common unit --
Income before cumulative effect of accounting change... $29,065 $17,454
Cumulative effect of accounting change................. -- 1,340
------- -------
$29,065 $18,794
======= =======
Denominator:
Denominator for basic earnings per common
unit -- weighted-average common units.................. 58,946 44,020
Effect of dilutive securities:
Unit options........................................... 275 74
Restricted units....................................... 21 10
------- -------
Denominator for diluted earnings per common
unit -- adjusted for weighted-average common units..... 59,242 44,104
======= =======
Basic and diluted earnings per common unit
Income before cumulative effect of accounting change...... $ 0.49 $ 0.40
Cumulative effect of accounting change.................... -- 0.03
------- -------
$ 0.49 $ 0.43
======= =======
8. RELATED PARTY TRANSACTIONS
There have been no changes to our related party relationships, except as
described below, from those described in Note 10 of our audited financial
statements filed in our 2003 Annual Report on Form 10-K, as amended.
Revenues received from related parties for the quarters ended March 31,
2004 and 2003, were approximately 13 percent of our total revenue.
Our transactions with related parties and affiliates are as follows:
QUARTER ENDED
MARCH 31,
-----------------
2004 2003
------- -------
(IN THOUSANDS)
Revenues received from related parties:
Natural gas pipelines and plants.......................... $20,686 $22,950
Oil and NGL logistics..................................... 8,359 6,869
------- -------
$29,045 $29,819
======= =======
Expenses paid to related parties:
Cost of natural gas and other products.................... $ 9,515 $14,975
Operation and maintenance................................. 22,587 23,717
------- -------
$32,102 $38,692
======= =======
Reimbursements received from related parties:
Operation and maintenance................................. $ 966 $ 525
======= =======
15
The following table provides summary data categorized by our related
parties:
QUARTER ENDED
MARCH 31,
-----------------
2004 2003
------- -------
(IN THOUSANDS)
Revenues received from related parties:
El Paso Corporation
El Paso Merchant Energy North America Company.......... $ 7,609 $10,812
El Paso Production Company............................. 2,262 2,358
Tennessee Gas Pipeline Company......................... -- 55
El Paso Field Services................................. 18,991 16,594
Enterprise................................................ 183 --
------- -------
$29,045 $29,819
======= =======
Cost of natural gas and other products paid to related
parties:
El Paso Corporation
El Paso Merchant Energy North America Company.......... $ 9,055 $10,278
El Paso Field Services................................. 402 4,677
El Paso Natural Gas Company............................ 19 20
Southern Natural Gas................................... 39 --
------- -------
$ 9,515 $14,975
======= =======
Operation and maintenance expenses paid to related parties:
El Paso Corporation
El Paso Field Services................................. $22,455 $23,624
Unconsolidated Subsidiaries
Poseidon Oil Pipeline Company.......................... 132 93
------- -------
$22,587 $23,717
======= =======
Reimbursements received from related parties:
Unconsolidated Subsidiaries
Cameron Highway........................................ $ 217 $ --
Deepwater Gateway...................................... 183 --
Poseidon Oil Pipeline Company.......................... 566 525
------- -------
$ 966 $ 525
======= =======
16
Our accounts receivable due from related parties consisted of the following
as of:
MARCH 31, DECEMBER 31,
2004 2003
------------- ------------
(IN THOUSANDS)
El Paso Corporation
El Paso Production Company................................ $ 6,373 $ 5,991
El Paso Merchant Energy North America Company............. 10,657 4,113
Tennessee Gas Pipeline Company............................ 1,559 1,350
El Paso Field Services.................................... 11,113 16,571
El Paso Natural Gas Company............................... 4,411 4,255
ANR Pipeline Company...................................... 1,662 1,600
Other..................................................... 54 830
Enterprise.................................................. 199 --
------- -------
36,028 34,710
------- -------
Unconsolidated Subsidiaries
Deepwater Gateway......................................... 4,319 3,939
Cameron Highway........................................... 7,375 9,302
Poseidon.................................................. 1,036 --
Other..................................................... -- 14
------- -------
12,730 13,255
------- -------
Total............................................. $48,758 $47,965
======= =======
Our accounts payable due to related parties consisted of the following as
of:
MARCH 31, DECEMBER 31,
2004 2003
------------- ------------
(IN THOUSANDS)
El Paso Corporation
El Paso Merchant Energy North America Company............. $ 9,270 $ 7,523
El Paso Production Company................................ 4,164 4,069
El Paso Field Services.................................... 13,750 13,869
Tennessee Gas Pipeline Company............................ 973 1,278
El Paso Natural Gas Company............................... 1,164 942
El Paso Corporation....................................... 1,322 6,249
Southern Natural Gas...................................... 20 1,871
Other..................................................... 671 667
------- -------
31,334 36,468
------- -------
Unconsolidated Subsidiaries
Deepwater Gateway......................................... 2,268 2,268
Poseidon.................................................. 774 --
Other..................................................... 10 134
------- -------
3,052 2,402
------- -------
Total............................................. $34,386 $38,870
======= =======
17
Other Matters
In connection with the sale of some of our Gulf of Mexico assets in January
2001, El Paso Corporation agreed to make quarterly payments to us of $2.25
million for three years beginning March 2001 and ending with a $2 million
payment in the first quarter of 2004, all of which have been received.
In addition to the related party transactions discussed above, pursuant to
the terms of many of the purchase and sale agreements we have entered into with
various entities controlled directly or indirectly by El Paso Corporation, we
have been indemnified for potential future liabilities, expenses and capital
requirements above a negotiated threshold. Specifically, an indirect subsidiary
of El Paso Corporation has agreed to indemnify us for specific litigation
matters to the extent the ultimate resolution of these matters results in
judgments against us. For a further discussion of these matters see Note 9,
Commitments and Contingencies, Legal Proceedings. Some of our agreements
obligate certain indirect subsidiaries of El Paso Corporation to pay for capital
costs related to maintaining assets which were acquired by us, if such costs
exceed negotiated thresholds. We have made claims for approximately $5 million
for costs incurred during the year ended December 31, 2003, as costs exceeded
the established thresholds for the year ended December 31, 2003.
We have also entered into capital contribution arrangements with entities
owned by El Paso Corporation, including its regulated pipelines, in the past,
and will most likely do so in the future, as part of our normal commercial
activities in the Gulf of Mexico. We have an agreement to receive $6.1 million,
of which $3.0 million has been collected as of March 31, 2004, from ANR Pipeline
Company for our Phoenix project. These amounts collected are reflected as a
reduction in project costs. Regulated pipelines often contribute capital toward
the construction costs of gathering facilities owned by others which are, or
will be, connected to their pipelines.
9. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
Grynberg. In 1997, we, along with numerous other energy companies, were
named defendants in actions brought by Jack Grynberg on behalf of the U.S.
Government under the False Claims Act. Generally, these complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Native American lands, which
deprived the U.S. Government of royalties. The plaintiff in this case seeks
royalties that he contends the government should have received had the volume
and heating value been differently measured, analyzed, calculated and reported,
together with interest, treble damages, civil penalties, expenses and future
injunctive relief to require the defendants to adopt allegedly appropriate gas
measurement practices. No monetary relief has been specified in this case. These
matters have been consolidated for pretrial purposes (In re: Natural Gas
Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming,
filed June 1997). Discovery is proceeding. Our costs and legal exposure related
to these lawsuits and claims are not currently determinable.
18
Will Price (formerly Quinque). We, along with numerous other energy
companies, are named defendants in Will Price, et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes
and heating content of natural gas on non-federal and non-Native American lands,
seek certification of a nationwide class of natural gas working interest owners
and natural gas royalty owners to recover royalties that they contend these
owners should have received had the volume and heating value of natural gas
produced from their properties been differently measured, analyzed, calculated
and reported, together with prejudgment and postjudgment interest, punitive
damages, treble damages, attorney's fees, costs and expenses, and future
injunctive relief to require the defendants to adopt allegedly appropriate gas
measurement practices. No monetary relief has been specified in this case.
Plaintiffs' motion for class certification of a nationwide class of natural gas
working interest owners and natural gas royalty owners was denied on April 10,
2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which
narrows the proposed class to royalty owners in wells in Kansas, Wyoming and
Colorado and removes claims as to heating content. A second class action
petition has been filed as to heating content claims. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.
In August 2002, we acquired the Big Thicket assets, which consist of the
Vidor plant, the Silsbee compressor station and the Big Thicket gathering system
located in east Texas, for approximately $11 million from BP America Production
Company (BP). Pursuant to the purchase agreement, we have identified
environmental conditions that we are working with BP and appropriate regulatory
agencies to address. BP has agreed to indemnify us for exposure resulting from
activities related to the ownership or operation of these facilities prior to
our purchase (i) for a period of three years for non-environmental claims and
(ii) until one year following the completion of any environmental remediation
for environmental claims. Following expiration of these indemnity periods, we
are obligated to indemnify BP for environmental or non-environmental claims. We,
along with BP and various other defendants, have been named in the following two
lawsuits for claims based on activities occurring prior to our purchase of these
facilities.
Christopher Beverly and Gretchen Beverly, individually and on behalf of the
estate of John Beverly v. GulfTerra GC, L.P., et. al. In June 2003, the
plaintiffs sued us in state district court in Hardin County, Texas, requesting
unspecified monetary damages. The plaintiffs are the parents of John Christopher
Beverly, a two year old child who died on April 15, 2002, allegedly as the
result of his exposure to arsenic, benzene and other harmful chemicals in the
water supply. Plaintiffs allege that several defendants are responsible for that
contamination, including us and BP. Our connection to the occurrences that are
the basis for this suit appears to be our August 2002 purchase of certain assets
from BP, including a facility in Hardin County, Texas known as the Silsbee
compressor station. Under the terms of the indemnity provisions in the Purchase
and Sale Agreement between us and BP, we requested that BP indemnify us for any
exposure. BP has agreed to indemnify us in this matter.
Melissa Duvail, et. al., v. GulfTerra GC, L.P., et. al. In June 2003,
seventy-four residents of Hardin County, Texas, sued us and others in state
district court in Hardin County, Texas, requesting unspecified monetary damages.
The plaintiffs allege that they have been exposed to hazardous chemicals,
including arsenic and benzene, through their water supply, and that the
defendants are responsible for that exposure. As with the Beverly case, our
connection with the occurrences that are the basis of this suit appears to be
our August 2002 purchase of certain assets from BP, including a facility known
as the Silsbee compressor station, which is located in Hardin County, Texas.
Under the terms of the indemnity provisions in the Purchase and Sale Agreement
between us and BP, BP has agreed to indemnify us for this matter.
Commodity Futures Trading Commission Investigation. On April 2, 2004,
certain affiliates of El Paso Corporation received subpoenas from the Commodity
Futures Trading Commission (CFTC) in connection with the CFTC's investigation of
reporting affecting the price of natural gas in the fall of 2003. Our two
storage fields, Petal and Wilson, are covered by this subpoena. Specifically,
the CFTC requested the companies to provide information, on behalf of themselves
and their affiliates, relating to storage reports provided to the Energy
Information Administration for the period October 2003 through December 2003. It
is our understanding that the CFTC is conducting an industry-wide investigation
of storage reporting. We are cooperating fully with the CFTC's investigation.
19
In connection with our April 2002 acquisition of the EPN Holding assets,
subsidiaries of El Paso Corporation have agreed to indemnify us against all
obligations related to existing legal matters at the acquisition date, including
the legal matters involving Leapartners, L.P. and City of Edinburg discussed
below.
During 2000, Leapartners, L.P. filed a suit against El Paso Field Services
and others in the District Court of Loving County, Texas, alleging a breach of
contract to gather and process natural gas in areas of western Texas related to
an asset now owned by GulfTerra Holding. In May 2001, the court ruled in favor
of Leapartners and entered a judgment against El Paso Field Services of
approximately $10 million. El Paso Field Services filed an appeal with the
Eighth Court of Appeals in El Paso, Texas. On August 15, 2003 the Court of
Appeals reversed the lower's courts calculation of past judgment interest but
otherwise affirmed the judgment. A petition for review by the Texas Supreme
Court was filed, and the Supreme Court has requested full briefing of the
issues.
Also, GulfTerra Texas Pipeline L.P., (GulfTerra Texas, formerly known as
EPGT Texas Pipeline L.P.) now owned by GulfTerra Holding, was involved in
litigation with the City of Edinburg concerning the City's claim that GulfTerra
Texas was required to pay pipeline franchise fees under a contract the City had
with Rio Grande Valley Gas Company, which was previously owned by GulfTerra
Texas and is now owned by Southern Union Gas Company. An adverse judgment
against Southern Union and GulfTerra Texas was rendered in Hidalgo County State
District court in December 1998 and found a breach of contract, and held both
GulfTerra Texas and Southern Union jointly and severally liable to the City for
approximately $4.7 million. The judgment relied on the single business
enterprise doctrine to impose contractual obligations on GulfTerra Texas and
Southern Union's entities that were not parties to the contract with the City.
GulfTerra Texas appealed this case to the Texas Supreme Court seeking reversal
of the judgment rendered against GulfTerra Texas. The City sought a remand to
the trial court of its claim of tortious interference against GulfTerra Texas.
Briefs were filed and oral arguments were held in November 2002. In October
2003, the Texas Supreme Court issued an opinion in favor of GulfTerra Texas and
Southern Union on all issues. The city sought rehearing which the Supreme Court
denied.
In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.
For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we will establish the necessary
accruals. As of March 31, 2004, we had no reserves for our legal matters.
While the outcome of our outstanding legal matters cannot be predicted with
certainty, based on information known to date, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, results of operations or cash flows. As new information becomes
available or relevant developments occur, we will establish accruals as
appropriate.
20
Environmental
Each of our operating segments is subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These laws and regulations are applicable to each segment and require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of March 2004,
we had a reserve of approximately $21 million, which is included in other
non-current liabilities on our balance sheets, for remediation costs expected to
be incurred over time associated with mercury meters. We assumed this liability
in connection with our April 2002 acquisition of the EPN Holding assets. As part
of the November 2002 San Juan assets acquisition, El Paso Corporation has agreed
to indemnify us for all the known and unknown environmental liabilities related
to the assets we purchased up to the purchase price of $766 million. We will be
indemnified for liabilities discovered during the proceeding three years from
the closing date of this acquisition. In addition, we have been indemnified by
third parties for remediation costs associated with other assets we have
purchased. We expect to make capital expenditures for environmental matters of
approximately $3 million in the aggregate for the years 2004 through 2008,
primarily to comply with clean air regulations.
Shoup Air Permit Violation. On December 16, 2003, El Paso Field Services,
L.P. received a Notice of Enforcement (NoE) from the Texas Commission on
Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at its
Shoup, Texas plant. The NoE included a draft Agreed Order assessing a penalty of
$365,750 for the cited violation. The alleged violations pertained to emission
limit exceedences, testing, reporting, and recordkeeping issues in 2001. While
the NoE was addressed to El Paso Field Services, L.P., the substance of the NoE
also concerns equipment owned at the Shoup plant by GulfTerra GC, L.P. El Paso
Field Services, L.P. responded to the NoE challenging several of the allegations
and the penalty amount and is awaiting a response from the TCEQ.
While the outcome of our outstanding environmental matters cannot be
predicted with certainty, based on the information known to date and our
existing accruals, we do not expect the ultimate resolution of these matters to
have a material adverse effect on our financial position, results of operations
or cash flows. It is possible that new information or future developments could
require us to reassess our potential exposure related to environmental matters.
We may incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or relevant
developments occur, we will adjust our accrual amounts accordingly. While there
are still uncertainties relating to the ultimate costs we may incur, based upon
our evaluation and experience to date, we believe our current reserves are
adequate.
Rates and Regulatory Matters
Marketing Affiliate Final Rule. In November 2003, the Federal Energy
Regulatory Commission (FERC) issued a Final Rule extending its standards of
conduct governing the relationship between interstate pipelines and marketing
affiliates to all energy affiliates. Since our High Island Offshore System
(HIOS) natural gas pipeline and Petal natural gas storage facility, including
the 60-mile Petal natural gas pipeline, are interstate facilities as defined by
the Natural Gas Act, the regulations dictate how HIOS and Petal conduct business
and interact with all energy affiliates of El Paso Corporation and us.
21
The standards of conduct require us, absent a waiver, to functionally
separate our HIOS and Petal interstate facilities from our other entities. We
must dedicate employees to manage and operate our interstate facilities
independently from our other Energy Affiliates. This employee group must
function independently and is prohibited from communicating non-public
transportation information or customer information to its Energy Affiliates.
Separate office facilities and systems are necessary because of the requirement
to restrict affiliate access to interstate transportation information. The Final
Rule also limits the sharing of employees and offices with Energy Affiliates.
The Final Rule was effective on February 9, 2004, and several requests for
rehearing were filed. On that date, each transmission provider filed with FERC
and posted on the internet website a plan and scheduling for implementing this
Final Rule. On April 8, 2004, we filed for an exemption from the rule on behalf
of Petal and HIOS. On April 16, 2004, the FERC issued its order on rehearing
which, among other things, affirmed that the final rule was needed and extended
the implementation date to September 1, 2004. At this time, we cannot predict
the impact of the final rule on HIOS and Petal's organizational structure, but
at a minimum, adoption of the regulations in the form outlined in the Final Rule
may place additional administrative and operational burdens on us.
Other Regulatory Matters. HIOS is subject to the jurisdiction of the FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. HIOS operates under a FERC approved tariff that governs its operations,
terms and conditions of service, and rates. We timely filed a required rate case
for HIOS on December 31, 2002. The rate filing and tariff changes are based on
HIOS' cost of service, which includes operating costs, a management fee and
changes to depreciation rates and negative salvage amortization. We requested
the rates be effective February 1, 2003, but the FERC suspended the rate
increase until July 1, 2003, subject to refund. As of July 1, 2003, HIOS
implemented the requested rates, subject to a refund, and has established a
reserve for its estimate of its refund obligation. We will continue to review
our expected refund obligation as the rate case moves through the hearing
process and may increase or decrease the amounts reserved for refund obligation
as our expectation changes. The FERC conducted a hearing on this matter and an
initial decision from the Administrative Law Judge was provided in April 2004.
We are in the process of filing briefs on our exceptions to this decision. We
are also in separate discussions with our customers to reach a settlement on
this rate case.
During the latter half of 2002, we experienced a significant unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast Region (and
these assets) in late September and early October of 2002. As of March 31, 2004,
we had recorded fuel differences of approximately $7.3 million, which is
included in other non-current assets on our balance sheets. We are currently in
discussions with the FERC as well as our customers regarding the potential
collection of some or all of the fuel differences. Any amount we are unable to
resolve or collect from our customers will negatively impact our earnings. At
this time we are not able to determine what amount, if any, may be collectible
from our customers.
In December 1999, GulfTerra Texas filed a petition with the FERC for
approval of its rates for interstate transportation service. In June 2002, the
FERC issued an order that required revisions to GulfTerra Texas' proposed
maximum rates. The changes ordered by the FERC involve reductions to rate of
return, depreciation rates and revisions to the proposed rate design, including
a requirement to separately state rates for gathering service. FERC also ordered
refunds to customers for the difference, if any, between the originally proposed
levels and the revised rates ordered by the FERC. We believe the amount of any
rate refund would be minimal since most transportation services are discounted
from the maximum rate. GulfTerra Texas has established a reserve for refunds. In
July 2002, GulfTerra Texas requested rehearing on certain issues raised by the
FERC's order, including the depreciation rates and the requirement to separately
state a gathering rate. On February 25, 2004, the FERC issued an order denying
GulfTerra Texas' request for rehearing and ordered GulfTerra Texas to file,
within 45 days from the issuance of the order, a calculation of refunds and a
refund plan. On March 22, 2004, the FERC extended the 45 day time limit to July
12, 2004. Additionally, the FERC ordered GulfTerra Texas to file a new rate case
or justification of existing rates within three years from the date of the
order. In March 2004, GulfTerra Texas filed for rehearing of the triennial rate
case requirement. The FERC plans to issue an order on rehearing of the triennial
rate case requirement by June 21, 2004.
22
In July 2002, Falcon Gas Storage, a competitor, also requested late
intervention and rehearing of the order. Falcon asserts that GulfTerra Texas'
imbalance penalties and terms of service preclude third parties from offering
imbalance management services. The FERC denied Falcon's late intervention in
February 2004. Meanwhile in December 2002, GulfTerra Texas amended its Statement
of Operating Conditions to provide shippers the option of resolving daily
imbalances using a third-party imbalance service provider.
Falcon filed a formal complaint in March 2003 at the Railroad Commission of
Texas claiming that GulfTerra Texas' imbalance penalties and terms of service
preclude third parties from offering hourly imbalance management services on the
GulfTerra Texas system. GulfTerra Texas filed a response specifically denying
Falcon's assertions and requesting that the complaint be denied. The Railroad
Commission has set their case for hearing beginning on June 29, 2004. The City
Board of Public Service of San Antonio filed an intervention in opposition to
Falcon's complaint.
While the outcome of all of our rates and regulatory matters cannot be
predicted with certainty, based on information known to date, we do not expect
the ultimate resolution of these matters to have a material adverse effect on
our financial position, results of operations or cash flows. As new information
becomes available or relevant developments occur, we will establish accruals as
appropriate.
Joint Ventures
We conduct a portion of our business through joint venture arrangements
(including our Cameron Highway, Deepwater Gateway and Poseidon joint ventures)
we form to construct, operate and finance the development of our onshore and
offshore midstream energy businesses. We are obligated to make our proportionate
share of additional capital contributions to our joint ventures only to the
extent that they are unable to satisfy their obligations from other sources
including proceeds from credit arrangements.
10. ACCOUNTING FOR HEDGING ACTIVITIES
A majority of our commodity purchases and sales, which relate to sales of
oil and natural gas associated with our production operations, purchases and
sales of natural gas associated with pipeline operations, sales of natural gas
liquids and purchases or sales of gas associated with our processing plants and
our gathering activities, are at spot market or forward market prices. We use
futures, forward contracts, and swaps to limit our exposure to fluctuations in
the commodity markets and allow for a fixed cash flow stream from these
activities.
We estimate the entire $13.3 million of unrealized losses included in
accumulated other comprehensive income at March 31, 2004, will be reclassified
from accumulated other comprehensive income as a reduction to earnings over the
next nine months. When our derivative financial instruments are settled, the
related amount in accumulated other comprehensive income is recorded in the
income statement in operating revenues, cost of natural gas and other products,
or interest and debt expense, depending on the item being hedged. The effect of
reclassifying these amounts to the income statement line items is recording our
earnings for the period related to the hedged items at the "hedged price" under
the derivative financial instruments.
In February and August 2003, we entered into derivative financial
instruments to continue to hedge our exposure during 2004 to changes in natural
gas prices relating to gathering activities in the San Juan Basin. The
derivatives are financial swaps on 30,000 MMBtu per day whereby we receive an
average fixed price of $4.23 per MMBtu and pay a floating price based on the San
Juan index. As of March 31, 2004, the fair value of these cash flow hedges was a
liability of $9.2 million, as the market price at that date was higher than the
hedge price. For the quarter ended March 31, 2004, we reclassified approximately
$1.7 million of unrealized accumulated loss related to these derivatives from
accumulated other comprehensive income as a decrease in revenue. No
ineffectiveness exists in this hedging relationship because all purchase and
sale prices are based on the same index and volumes as the hedge transaction.
23
During 2003, we entered into additional derivative financial instruments to
hedge a portion of our business' exposure to changes in natural gas liquids
(NGL) prices during 2004. We entered into financial swaps for 6,000 barrels per
day for the period from August 2003 to September 2004. The average fixed price
received is $0.47 per gallon for 2004 while we pay a monthly average floating
price based on the Oil Pricing Information Service (OPIS) average price for each
month. As of March 31, 2004, the fair value of these cash flow hedges was a
liability of $4.1 million. For the quarter ended March 31, 2004, we reclassified
approximately $2.1 million of unrealized accumulated loss related to these
derivatives from accumulated other comprehensive income to earnings. No
ineffectiveness exists in this hedging relationship because all purchase and
sales prices are based on the same index and volumes as the hedge transaction.
In connection with our GulfTerra Intrastate Alabama operations, we have
fixed price contracts with specific customers for the sale of predetermined
volumes of natural gas for delivery over established periods of time. We entered
into cash flow hedges in 2003 to offset the risk of increasing natural gas
prices. For January and February 2004, we contracted to purchase 20,000 MMBtu
and for March 2004, we contracted to purchase 15,000 MMBtu. The average fixed
price paid during 2004 was $5.28 per MMBtu while we received a floating price
based on the SONAT-Louisiana index (Southern Natural Pipeline index as published
by the periodical "Inside FERC"). As of March 31, 2004, these cash flow hedges
expired and we reclassified a gain of approximately $45 thousand from
accumulated other comprehensive income to earnings. No ineffectiveness existed
in this hedging relationship because all purchase and sale prices were based on
the same index and volumes as the hedge transaction.
In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million of our 8 1/2% senior subordinated notes
due 2011. With this swap agreement, we paid the counterparty a LIBOR based
interest rate plus a spread of 4.20% and received a fixed rate of 8 1/2%. We
accounted for this derivative as a fair value hedge under SFAS No. 133. In March
2004, we terminated our fixed to floating interest rate swap with our
counterparty. The value of the transaction at termination was zero and as such
neither we, nor our counterparty, were required to make any payments. Also,
neither we, nor our counterparty, have any future obligations under this
transaction.
The counterparties for our San Juan hedging activities are J. Aron and
Company, an affiliate of Goldman Sachs, and UBS Warburg. We do not require
collateral and do not anticipate non-performance by these counterparties. The
counterparty for our GulfTerra Alabama Intrastate operations is UBS Warburg, and
we do not require collateral or anticipate non-performance by this counterparty.
11. BUSINESS SEGMENT INFORMATION
Each of our segments are business units that offer different services and
products that are managed separately since each segment requires different
technology and marketing strategies. We have segregated our business activities
into four distinct operating segments:
- Natural gas pipelines and plants;
- Oil and NGL logistics;
- Natural gas storage; and
- Platform services.
24
We use performance cash flows (which we formerly referred to as EBITDA) to
evaluate the performance of our segments, determine how resources will be
allocated and develop strategic plans. We define performance cash flows as
earnings before interest, depreciation and amortization and other adjustments.
Historically our lenders and equity investors have viewed our performance cash
flows measure as an indication of our ability to generate sufficient cash to
meet debt obligations or to pay distributions. We believe that there has been a
shift in investors' evaluation regarding investments in MLPs and they now put as
much focus on the performance of an MLP investment as they do its ability to pay
distributions. For that reason, we disclose performance cash flows as a measure
of our segment's performance.
We believe performance cash flows is also useful to our investors because
it allows them to evaluate the effectiveness of our business segments from an
operational perspective, exclusive of the costs to finance those activities and
depreciation and amortization, neither of which are directly relevant to the
efficiency of those operations. This measurement may not be comparable to
measurements used by other companies and should not be used as a substitute for
net income or other performance measures.
The following are results as of and for the quarters ended March 31:
NATURAL GAS OIL AND NATURAL
PIPELINES AND NGL GAS PLATFORM NON-SEGMENT
PLANTS LOGISTICS STORAGE SERVICES ACTIVITY(1) TOTAL
------------- ---------- -------- -------- ----------- ----------
(IN THOUSANDS)
QUARTER ENDED MARCH 31, 2004
Revenue from external
customers.................... $ 181,503 $ 15,188 $ 12,450 $ 6,642 $ 4,556 $ 220,339
Intersegment revenue........... 33 -- -- 585 (618) --
Depreciation, depletion and
amortization................. 17,388 3,092 2,948 1,353 1,442 26,223
Earnings from unconsolidated
affiliates................... 534 1,790 (30) (86) -- 2,208
Performance cash flows......... 82,013 7,468 9,061 6,363 N/A N/A
Assets......................... 2,329,952 472,482 311,326 167,044 83,212 3,364,016
QUARTER ENDED MARCH 31, 2003
Revenue from external
customers(2)................. $ 197,189 $ 11,968 $ 11,606 $ 4,382 $ 4,950 $ 230,095
Intersegment revenue........... 38 -- 92 646 (776) --
Depreciation, depletion and
amortization................. 16,553 2,197 2,962 1,200 785 23,697
Earnings from unconsolidated
affiliates................... 629 2,687 -- -- -- 3,316
Performance cash flows......... 77,835 11,600 7,001 4,235 N/A N/A
Assets......................... 2,249,828 322,324 326,795 160,128 108,407 3,167,482
- ----------
(1) Represents predominantly our oil and natural gas production activities as
well as intersegment eliminations. Our intersegment revenues, along with our
intersegment operating expenses, consist of normal course of business-type
transactions between our operating segments. We record an intersegment
revenue elimination, which is the only elimination included in the
"Non-Segment Activity" column, to remove intersegment transactions.
(2) Revenue from external customers for our Oil and NGL Logistics segment has
been reduced by $48.8 million to reflect the revision of Typhoon Oil
Pipeline's revenues and cost of natural gas and other products to conform to
the current period presentation. See Note 1, Basis of Presentation and
Summary of Significant Accounting Policies; Revenue Recognition and Cost of
Natural Gas and Other Products.
25
A reconciliation of our segment performance cash flows to our net income is
as follows:
QUARTER ENDED
MARCH 31,
-------------------
2004 2003
-------- --------
(IN THOUSANDS)
Natural gas pipelines and plants............................ $ 82,013 $ 77,835
Oil and NGL logistics....................................... 7,468 11,600
Natural gas storage......................................... 9,061 7,001
Platform services........................................... 6,363 4,235
-------- --------
Segment performance cash flows............................ 104,905 100,671
Plus: Other, nonsegment results............................. 5,405 5,266
Earnings from unconsolidated affiliates............... 2,208 3,316
Cumulative effect of accounting change................ -- 1,690
Less: Interest and debt expense............................. 28,031 34,486
Loss due to write-off of unamortized debt issuance
costs..................................................... -- 3,762
Depreciation, depletion and amortization.............. 26,223 23,697
Cash distributions from unconsolidated affiliates..... 750 4,710
Minority interest..................................... (12) 33
Net cash payment received from El Paso Corporation.... 1,960 2,040
-------- --------
Net income.................................................. $ 55,566 $ 42,215
======== ========
12. GUARANTOR FINANCIAL INFORMATION
As of March 31, 2004 and December 31, 2003, our credit facility is
guaranteed by each of our subsidiaries, excluding our unrestricted subsidiaries
(Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.), and is
collateralized by substantially all of our assets. In addition, all of our
senior notes and senior subordinated notes are jointly, severally, fully and
unconditionally guaranteed by us and all of our subsidiaries, excluding our
unrestricted subsidiaries. Non-guarantor subsidiaries for the quarter ended
March 31, 2004, consisted of our unrestricted subsidiaries. Non-guarantor
subsidiaries for the quarter ended March 31, 2003, consisted of Matagorda Island
Area Gathering System, Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas,
L.L.C.
The following condensed consolidating financial statements are included so
that separate financial statements of our guarantor subsidiaries are not
required to be filed with the SEC. These condensed consolidating financial
statements present our investments in both consolidated subsidiaries and
unconsolidated affiliates using the equity method of accounting. The
consolidating eliminations column on our condensed consolidating balance sheets
below eliminates our investment in consolidated subsidiaries, intercompany
payables and receivables and other transactions between subsidiaries. The
consolidating eliminations column in our condensed consolidating statements of
income and cash flows eliminates earnings from our consolidated affiliates.
26
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
QUARTER ENDED MARCH 31, 2004
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Operating revenues................ $ -- $134 $220,205 $ -- $220,339
------- ---- -------- -------- --------
Operating expenses
Cost of natural gas and other
products..................... -- -- 64,427 -- 64,427
Operation and maintenance....... -- 63 48,433 -- 48,496
Depreciation, depletion and
amortization................. 36 -- 26,187 -- 26,223
Gain on sale of long-lived
assets....................... -- -- (24) -- (24)
------- ---- -------- -------- --------
36 63 139,023 -- 139,122
------- ---- -------- -------- --------
Operating income (loss)........... (36) 71 81,182 -- 81,217
Earnings from consolidated
affiliates...................... 65,833 -- -- (65,833) --
Earnings (loss) from
unconsolidated affiliates....... -- (30) 2,238 -- 2,208
Minority interest income.......... -- 12 -- -- 12
Other income...................... 73 -- 87 -- 160
Interest and debt expense......... 10,304 (7) 17,734 -- 28,031
------- ---- -------- -------- --------
Net income...................... $55,566 $ 60 $ 65,773 $(65,833) $ 55,566
======= ==== ======== ======== ========
27
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
QUARTER ENDED MARCH 31, 2003
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES(1) ELIMINATIONS TOTAL
------- ------------- --------------- ------------- ------------
(IN THOUSANDS)
Operating revenues............... $ -- $277 $229,818 $ -- $230,095
------- ---- -------- -------- --------
Operating expenses
Cost of natural gas and other
products.................... -- -- 90,753 -- 90,753
Operation and maintenance...... 467 74 40,103 -- 40,644
Depreciation, depletion and
amortization................ 37 10 23,650 -- 23,697
Gain on sale of long-lived
assets...................... -- -- (106) -- (106)
------- ---- -------- -------- --------
504 84 154,400 -- 154,988
------- ---- -------- -------- --------
Operating income (loss).......... (504) 193 75,418 -- 75,107
Earnings from consolidated
affiliates..................... 61,505 -- -- (61,505) --
Earnings from unconsolidated
affiliates..................... -- -- 3,316 -- 3,316
Minority interest expense........ -- (33) -- -- (33)
Other income..................... 248 -- 135 -- 383
Interest and debt expense........ 15,272 -- 19,214 -- 34,486
Loss due to write-off of
unamortized debt issuance
costs.......................... 3,762 -- -- -- 3,762
------- ---- -------- -------- --------
Income before cumulative effect
of accounting change........... 42,215 160 59,655 (61,505) 40,525
Cumulative effect of accounting
change......................... -- -- 1,690 -- 1,690
------- ---- -------- -------- --------
Net income..................... $42,215 $160 $ 61,345 $(61,505) $ 42,215
======= ==== ======== ======== ========
- ---------------
(1) Operating revenues and cost of natural gas and other products for our
guarantor subsidiaries has been reduced by $48.8 million to reflect the
revision of Typhoon Oil Pipeline's revenues and cost of natural gas and
other products to conform to the current period presentation. See Note 1,
Basis of Presentation and Summary of Significant Accounting Policies;
Revenue Recognition and Cost of Natural Gas and Other Products.
28
CONDENSED CONSOLIDATING BALANCE SHEETS
MARCH 31, 2004
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
---------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Current assets
Cash and cash equivalents.... $ 23,257 $ -- $ -- $ -- $ 23,257
Accounts receivable, net
Trade..................... 2,287 80 115,307 -- 117,674
Affiliates................ 747,417 206 44,331 (743,196) 48,758
Affiliated note receivable... -- 3,713 -- -- 3,713
Other current assets......... 6,675 -- 16,850 -- 23,525
---------- ------ ---------- ----------- ----------
Total current assets...... 779,636 3,999 176,488 (743,196) 216,927
Property, plant and equipment,
net.......................... 8,508 431 2,907,545 -- 2,916,484
Intangible assets.............. -- -- 3,309 -- 3,309
Investment in unconsolidated
affiliates................... -- -- 190,732 -- 190,732
Investment in consolidated
affiliates................... 2,169,692 -- 700 (2,170,392) --
Other noncurrent assets........ 198,495 -- 8,068 (169,999) 36,564
---------- ------ ---------- ----------- ----------
Total assets................. $3,156,331 $4,430 $3,286,842 $(3,083,587) $3,364,016
========== ====== ========== =========== ==========
Current liabilities
Accounts payable
Trade..................... $ -- $ 17 $ 105,454 $ -- $ 105,471
Affiliates................ 9,101 -- 768,481 (743,196) 34,386
Accrued interest............. 33,982 -- -- -- 33,982
Current maturities of senior
secured term loan......... 3,000 -- -- -- 3,000
Other current liabilities.... 7,171 -- 33,531 -- 40,702
---------- ------ ---------- ----------- ----------
Total current
liabilities............. 53,254 17 907,466 (743,196) 217,541
Revolving credit facility...... 387,000 -- -- -- 387,000
Senior secured term loans, less
current maturities........... 297,000 -- -- -- 297,000
Long-term debt................. 1,137,161 -- -- -- 1,137,161
Other noncurrent liabilities... (1) -- 211,596 (169,999) 41,596
Minority interest.............. -- 1,801 -- -- 1,801
Partners' capital.............. 1,281,917 2,612 2,167,780 (2,170,392) 1,281,917
---------- ------ ---------- ----------- ----------
Total liabilities and
partners' capital......... $3,156,331 $4,430 $3,286,842 $(3,083,587) $3,364,016
========== ====== ========== =========== ==========
29
CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2003
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
---------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Current assets
Cash and cash equivalents.... $ 30,425 $ -- $ -- $ -- $ 30,425
Accounts receivable, net.....
Trade..................... -- 113 106,157 -- 106,270
Affiliates................ 746,126 3,541 41,606 (743,308) 47,965
Affiliated note receivable... -- 3,713 55 -- 3,768
Other current assets......... 3,573 -- 17,022 -- 20,595
---------- ------ ---------- ----------- ----------
Total current
assets............. 780,124 7,367 164,840 (743,308) 209,023
Property, plant and equipment,
net.......................... 8,039 431 2,886,022 -- 2,894,492
Intangible assets.............. -- -- 3,401 -- 3,401
Investment in unconsolidated
affiliates................... -- -- 175,747 -- 175,747
Investment in consolidated
affiliates................... 2,108,104 -- 622 (2,108,726) --
Other noncurrent assets........ 199,761 -- 9,155 (169,999) 38,917
---------- ------ ---------- ----------- ----------
Total assets......... $3,096,028 $7,798 $3,239,787 $(3,022,033) $3,321,580
========== ====== ========== =========== ==========
Current liabilities
Accounts payable.............
Trade..................... $ -- $ 22 $ 129,241 $ -- $ 129,263
Affiliates................ 10,691 3,499 767,988 (743,308) 38,870
Accrued interest............. 10,930 -- 269 -- 11,199
Current maturities of senior
secured term loan......... 3,000 -- -- -- 3,000
Other current liabilities.... 2,601 1 24,433 -- 27,035
---------- ------ ---------- ----------- ----------
Total current
liabilities........ 27,222 3,522 921,931 (743,308) 209,367
Revolving credit facility...... 382,000 -- -- -- 382,000
Senior secured term loan, less
current maturities........... 297,000 -- -- -- 297,000
Long-term debt................. 1,129,807 -- -- -- 1,129,807
Other noncurrent liabilities... 7,413 -- 211,629 (169,999) 49,043
Minority interest.............. -- 1,777 -- -- 1,777
Partners' capital.............. 1,252,586 2,499 2,106,227 (2,108,726) 1,252,586
---------- ------ ---------- ----------- ----------
Total liabilities and
partners'
capital............ $3,096,028 $7,798 $3,239,787 $(3,022,033) $3,321,580
========== ====== ========== =========== ==========
30
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
QUARTER ENDED MARCH 31, 2004
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
-------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Cash flows from operating activities
Net income................................... $ 55,566 $ 60 $ 65,773 $(65,833) $ 55,566
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation, depletion and amortization... 36 -- 26,187 -- 26,223
Distributed earnings of unconsolidated
affiliates
Earnings from unconsolidated
affiliates............................ -- 30 (2,238) -- (2,208)
Distributions from unconsolidated
affiliates............................ -- -- 750 -- 750
Gain on sale of long-lived assets.......... -- -- (24) -- (24)
Amortization of debt issuance costs........ 1,358 -- -- -- 1,358
Other noncash items........................ 604 24 2,408 -- 3,036
Working capital changes, net of effects of
acquisitions and noncash transactions...... 22,518 (61) (43,698) -- (21,241)
-------- ---- -------- -------- --------
Net cash provided by operating
activities.......................... 80,082 53 49,158 (65,833) 63,460
-------- ---- -------- -------- --------
Cash flows from investing activities
Additions to property, plant and equipment... (505) -- (47,328) -- (47,833)
Proceeds from sale and retirement of
assets..................................... -- -- 93 -- 93
Additions to investments in unconsolidated
affiliates................................. -- -- (5,800) -- (5,800)
-------- ---- -------- -------- --------
Net cash used in investing
activities.......................... (505) -- (53,035) -- (53,540)
-------- ---- -------- -------- --------
Cash flows from financing activities
Net proceeds from revolving credit
facility................................... 44,933 -- -- -- 44,933
Repayments of revolving credit facility...... (40,000) -- -- -- (40,000)
Net proceeds from senior secured term loan... (57) -- -- -- (57)
Net proceeds from issuance of long-term
debt....................................... (30) -- -- -- (30)
Net proceeds from issuance of common units... 48,274 -- -- -- 48,274
Advances with affiliates..................... (69,657) (53) 3,877 65,833 --
Distributions to partners.................... (70,529) -- -- -- (70,529)
Contribution from general partner............ 321 -- -- -- 321
-------- ---- -------- -------- --------
Net cash provided by (used in)
financing activities................ (86,745) (53) 3,877 65,833 (17,088)
-------- ---- -------- -------- --------
Decrease in cash and cash equivalents.......... $ (7,168) $ -- $ -- $ -- (7,168)
======== ==== ======== ========
Cash and cash equivalents at beginning of
period....................................... 30,425
--------
Cash and cash equivalents at end of period..... $ 23,257
========
31
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
QUARTER ENDED MARCH 31, 2003
NON-GUARANTOR GUARANTOR CONSOLIDATING CONSOLIDATED
ISSUER SUBSIDIARIES SUBSIDIARIES ELIMINATIONS TOTAL
--------- ------------- ------------ ------------- ------------
(IN THOUSANDS)
Cash flows from operating activities
Net income............................... $ 42,215 $ 160 $ 61,345 $(61,505) $ 42,215
Less cumulative effect of accounting
change................................. -- -- 1,690 -- 1,690
--------- ----- -------- -------- ---------
Income before cumulative effect of
accounting change...................... 42,215 160 59,655 (61,505) 40,525
Adjustments to reconcile net income to
net cash provided by operating
activities
Depreciation, depletion and
amortization......................... 37 10 23,650 -- 23,697
Distributed earnings of unconsolidated
affiliates
Earnings from unconsolidated
affiliates........................ -- -- (3,316) -- (3,316)
Distributions from unconsolidated
affiliates........................ -- -- 4,710 -- 4,710
Gain on sale of long-lived assets...... -- -- (106) -- (106)
Loss due to write-off of unamortized
debt issuance costs.................. 3,762 -- -- -- 3,762
Amortization of debt issuance costs.... 1,938 -- 154 -- 2,092
Other noncash items.................... 270 33 220 -- 523
Working capital changes, net of effects
of acquisitions and noncash
transactions........................... 17,888 (170) (18,161) -- (443)
--------- ----- -------- -------- ---------
Net cash provided by operating
activities...................... 66,110 33 66,806 (61,505) 71,444
--------- ----- -------- -------- ---------
Cash flows from investing activities
Additions to property, plant and
equipment.............................. (309) -- (81,628) -- (81,937)
Proceeds from sale and retirement of
assets................................. -- -- 3,088 -- 3,088
Additions to investments in
unconsolidated affiliates.............. -- (133) -- -- (133)
--------- ----- -------- -------- ---------
Net cash used in investing
activities...................... (309) (133) (78,540) -- (78,982)
--------- ----- -------- -------- ---------
Cash flows from financing activities
Net proceeds from revolving credit
facility............................... 98,991 -- -- -- 98,991
Repayments of revolving credit
facility............................... (119,000) -- -- -- (119,000)
Repayment of senior secured acquisition
term loan.............................. (237,500) -- -- -- (237,500)
Net proceeds from issuance of long-term
debt................................... 293,277 -- -- -- 293,277
Advances with affiliates................. (63,775) 100 2,170 61,505 --
Distributions to partners................ (52,080) -- -- -- (52,080)
--------- ----- -------- -------- ---------
Net cash provided by (used in)
financing activities............ (80,087) 100 2,170 61,505 (16,312)
--------- ----- -------- -------- ---------
Decrease in cash and cash equivalents...... $ (14,286) $ -- $ (9,564) $ -- (23,850)
========= ===== ======== ========
Cash and cash equivalents at beginning of
period................................. 36,099
---------
Cash and cash equivalents at end of
period................................. $ 12,249
=========
32
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in Part II, Items 7, 7A and 8, in our
Annual Report on Form 10-K, as amended, for the year ended December 31, 2003, in
addition to the interim financial statements and notes presented in Item 1 of
this Quarterly Report on Form 10-Q.
In the first quarter of 2004, we advanced numerous Gulf of Mexico pipeline
and platform projects which will make contributions in the second half of 2004
and we continued to make progress on our planned merger with Enterprise. The
Marco Polo TLP was installed in the first quarter and is being commissioned by
Anadarko Petroleum Corporation with expected first deliveries in early summer.
Construction on our Marco Polo oil and gas gathering systems is largely
complete. Additionally, the Cameron Highway oil pipeline system project is on
track to be placed in-service later this year with first production expected in
late 2004. Additionally, our Phoenix gathering system is largely complete and we
expect first production by mid-year from Kerr-McGee's Red Hawk Deepwater
development.
MERGER WITH ENTERPRISE
On December 15, 2003, we, along with Enterprise and El Paso Corporation,
announced that we had executed definitive agreements to merge Enterprise and
GulfTerra to form one of the largest publicly traded MLPs.
In April 2004, Enterprise and El Paso Corporation amended their agreement
with respect to the ownership of Enterprise's general partner interest upon the
completion of our merger with Enterprise.
As originally envisioned in the merger agreement, El Paso Corporation was
to contribute its 50-percent ownership interest in our general partner to
Enterprise's general partner, in exchange for a 50-percent ownership interest in
Enterprise's general partner. Under the amended transaction, El Paso Corporation
will still contribute its 50-percent ownership interest in our general partner
to Enterprise's general partner, but in exchange, El Paso Corporation will
receive a 9.9-percent ownership interest in Enterprise's general partner and
$370 million in cash. The remaining 90.1-percent ownership interest in
Enterprise's general partner will continue to be owned by affiliates of
privately-held Enterprise Products Company.
The remaining transactions with respect to our merger with Enterprise are
unchanged. These include:
- the payment of $500 million in cash from Enterprise to El Paso
Corporation for approximately 13.8 million units, which include 2.9
million of our common units and all of our Series C units owned by El
Paso Corporation;
- the exchange of 1.81 Enterprise common units for each GulfTerra common
unit owned by GulfTerra's unitholders, including the remaining
approximately 7.5 million GulfTerra common units owned by El Paso
Corporation.
MERGER RELATED COSTS
As a result of the pending merger with Enterprise, we determined that it
was in our and our unitholders' best interest to offer selected employees of El
Paso Corporation incentives to continue to focus on the business of the
partnership during the merger process. We have accounted for these incentives
under the provisions of SFAS No. 146, Accounting for Costs Associated with Exit
or Disposal Activities. As of March 31, 2004, we recorded a liability and a
related deferred charge of $4.3 million, which are reflected in other current
liabilities and other current assets on our balance sheets. Our liability was
estimated based upon the number of employees accepting the offer and the
discounted amount they are expected to be paid. We are amortizing the deferred
asset to expense ratably over the expected period of the services required in
order to qualify for receiving the payments. We expect to amortize the entire
expense by merger close. During the quarter ended March 31, 2004, we had
amortized $0.6 million to expense. If our expectations of future amounts to be
paid or the period of service to be rendered change, we will adjust our
liability.
33
Additionally, during the first quarter of 2004, we recognized an expense of
$3.5 million associated with a fairness opinion we received on our pending
merger with Enterprise. All of our merger related costs are included in
operation and maintenance expenses on our statements of income and are allocated
across all of our operating segments.
LIQUIDITY AND CAPITAL RESOURCES
Our principal requirements for cash, other than our routine operating
costs, are for capital expenditures, debt service, business acquisitions and
distributions to our partners. We plan to fund our short-term cash needs,
including operating costs, maintenance capital expenditures and cash
distributions to our partners, from cash generated from our operating activities
and borrowings under our credit facility. Capital expenditures we expect to
benefit us over longer time periods, including our organic growth projects and
business acquisitions, we plan to fund through a variety of sources (either
separately or in combination), which include issuing additional common units,
borrowing under commercial bank credit facilities, issuing public or private
placement debt and other financing transactions. We plan to fund our debt
service requirements through a combination of refinancing arrangements and cash
generated from our operating activities. As previously discussed, our merger
agreement with Enterprise limits our ability to raise additional capital and
incur additional indebtedness prior to the closing of the merger without
Enterprise's approval; however, we believe that these limitations will not
affect our liquidity.
CAPITAL RESOURCES
SERIES F CONVERTIBLE UNITS
In connection with a public offering in May 2003, we issued 80 Series F
convertible units convertible into a maximum of 8,329,679 common units and
comprised of two separate detachable units. The Series F1 units are convertible
into up to $80 million of common units anytime after August 12, 2003, and until
the date we merge with Enterprise (subject to other defined extension rights).
The Series F2 units are convertible into up to $40 million of common units prior
to March 30, 2005 (subject to defined extension rights). The price at which the
Series F convertible units may be converted to common units is equal to the
lesser (i) of the prevailing price (as defined below), if the prevailing price
is equal to or greater than $35.75, or (ii) the prevailing price minus the
product of 50 percent of the positive difference, if any, of $35.75 minus the
prevailing price. The prevailing price is equal to the lesser of (i) the average
closing price of our common units for the 60 business days ending on and
including the fourth business day prior to our receiving notice from the holder
of the Series F convertible units of their intent to convert them into common
units, (ii) the average closing price of our common units for the first seven
business days of the 60 day period included in (i); or (iii) the average closing
price of our common units for the last seven business days of the 60 day period
included in (i). The price at which the Series F convertible units could have
been converted to common units, assuming we had received a conversion notice on
March 31, 2004 and May 3, 2004, was $41.12 and $39.01 per common unit. Holders
of Series F convertible units are not entitled to vote or to receive
distributions. The value of the Series F convertible units was $2.6 million as
of March 31, 2004, and is included in partners' capital as a component of common
units.
In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26 per unit, paying the holder an amount of cash equal
to the market price of the net number of units. These amendments had no effect
on the classification of the Series F convertible units on the balance sheet at
March 31, 2004 and December 31, 2003.
In the first quarter of 2004, 45 Series F1 convertible units were converted
into 1,146,418 common units, for which the holder of the convertible units paid
us $45 million. Additionally, our general partner contributed to us $0.3 million
in cash in order to maintain its one percent general partner interest.
Any Series F1 convertible units for which a conversion notice has not been
delivered prior to the merger closing date, or termination of the merger, will
expire upon the closing, or termination, of the merger with
34
Enterprise. Any Series F2 convertible units outstanding at the merger date will
be converted into rights to receive Enterprise common units, subject to the
restrictions governing the Series F units. The number of Enterprise common units
and the price per unit at conversion will be adjusted based on the 1.81 exchange
ratio.
INDEBTEDNESS AND OTHER OBLIGATIONS
In March 2004, we gave notice to exercise our right, under the terms of our
senior subordinated notes' indentures, to repay, at a premium, approximately
$39.1 million in principal amount of our 8 1/2% senior subordinated notes due
June 2010. We will recognize additional costs totaling $4.1 million resulting
from the payment of the redemption premiums and the write-off of unamortized
debt issuance costs. We will account for these costs as an expense during the
second quarter of 2004 in accordance with the provisions of SFAS No. 145.
In April 2004, we initiated a full redemption of all our outstanding $175
million aggregate principal amount of 10 3/8% senior subordinated notes due
2009. The notes will be redeemed on June 1, 2004, at a redemption price of
105.2% of the principal amount, plus accrued and unpaid interest to June 1,
2004. Interest on the notes will cease to accrue on and after June 1, 2004, and
the only remaining right of holders of the notes will be to receive payment of
the redemption price upon surrender to the paying agent, plus accrued and unpaid
interest up to, but not including, June 1, 2004. In connection with the
redemption of the notes, we will recognize additional expense during the second
quarter of 2004 totaling $12.1 million resulting from the payment of the
redemption premium and the write-off of unamortized debt issuance costs. We will
fund the redemption with internally generated funds and borrowings under our
credit facility.
See Item 1., Financial Statements, Note 5, for additional discussion of our
debt obligations.
The following table presents the timing and amounts of our debt repayment
and other obligations for the years following March 31, 2004, that we believe
could affect our liquidity (in millions):
LESS THAN AFTER
DEBT REPAYMENT AND OTHER OBLIGATIONS 1 YEAR 1-3 YEARS 3-5 YEARS 5 YEARS TOTAL
------------------------------------ --------- --------- --------- ------- ------
Revolving credit facility................. $ -- $387 $ -- $ -- $ 387
Senior secured term loan.................. 3 6 291 -- 300
6 1/4% senior notes issued July 2003, due
June 2010............................... -- -- -- 250 250
10 3/8% senior subordinated notes issued
May 1999, due June 2009................. -- -- -- 175 175
8 1/2% senior subordinated notes issued
March 2003, due June 2010............... -- -- -- 255 255
8 1/2% senior subordinated notes issued
May 2001, due June 2011................. -- -- -- 168 168
8 1/2% senior subordinated notes issued
May 2002, due June 2011................. -- -- -- 154 154
10 5/8% senior subordinated notes issued
November 2002, due December 2012........ -- -- -- 134 134
Wilson natural gas storage facility
operating lease......................... 5 10 5 -- 20
Texas leased NGL storage facilities....... 2 2 1 2 7
---- ---- ---- ------ ------
Total debt repayment and other
obligations..................... $ 10 $405 $297 $1,138 $1,850
==== ==== ==== ====== ======
The close of the merger will constitute a change of control, and thus a
default, under our credit facility, therefore we will either repay or amend that
facility prior to the close. In addition, the merger close will constitute a
change of control under our indentures, and we will be required to offer to
repurchase our outstanding senior subordinated notes (and possibly our senior
notes) at 101 percent of their principal amount
35
after the close. In coordination with Enterprise, we are evaluating alternative
financing plans in preparation for the close of the merger. We and Enterprise
can agree on the date of the merger close after the receipt of all necessary
approvals. We do not intend to close until appropriate financing is in place.
INDUSTRIAL REVENUE BONDS
In April 2004, we reduced the sales tax assessable by the State of
Mississippi related to our Petal natural gas storage expansion and pipeline
project completed in September 2002, by completing that project's qualification
for tax incentives available under the MBFA. To complete the qualification,
Petal, our indirect, wholly-owned subsidiary, borrowed $52 million from the MBFC
pursuant to a loan agreement between Petal and the MBFC. On the same date, the
MBFC issued $52.0 million in Industrial Development Revenue Bonds to us. The
loan agreement and the Industrial Development Revenue Bonds have identical
interest rates of 6.25% and maturities of fifteen years. The bonds and tax
exemptions are authorized under the MBFA. Petal may repay the loan agreement
without penalty, and thus cause the Industrial Development Revenue Bonds to be
redeemed, any time after one year from their date of issue.
CAPITAL EXPENDITURES
The ability to execute our growth strategy and complete our projects is
dependent upon our access to the capital necessary to fund projects and
acquisitions. Our success with capital raising efforts, including the formation
of joint ventures to share costs and risks, continues to be the critical factor
which determines how much we actually spend. We believe our access to capital
resources is sufficient to meet the demands of our current and future operating
growth needs and, although we currently intend to make the forecasted
expenditures discussed below, we may adjust the timing and amounts of projected
expenditures as necessary to adapt to changes in the capital markets.
Under the merger agreement with Enterprise, we can not make capital
expenditures, without Enterprise's consent, in excess of $5 million or $25
million in the aggregate other than (1) as required on an emergency basis and
(2) those planned expenditures previously disclosed to Enterprise. The
forecasted expenditures disclosed in the tables below were either consented to
by Enterprise, planned expenditures previously disclosed to Enterprise or
expenditures which fall within the monetary thresholds in the merger agreement.
We estimate our forecasted expenditures based upon our strategic operating
and growth plans, which are also dependent upon our ability to produce or
otherwise obtain the capital necessary to accomplish our operating and growth
objectives. These estimates may change due to factors beyond our control, such
as weather related issues, changes in supplier prices or poor economic
conditions. Further, estimates may change as a result of decisions made at a
later date, which may include acquisitions, scope changes or decisions to take
on additional partners. Our projection of expenditures for the quarter March 31,
2004 as presented in our 2003 Annual Report on Form 10-K, as amended, was $76
million; however, our actual expenditures were approximately $48 million.
36
The table below depicts our estimate of projects and capital maintenance
expenditures through March 31, 2005. These estimates are net of anticipated
contributions in aid of construction and contributions from joint venture
partners. We expect to be able to fund these forecasted expenditures from the
combination of operating cash flow and funds available under our revolving
credit facility and other financing arrangements. Actual results may vary from
these projections. We do not disclose planned expenditures related to our
offshore projects unless we have signed definitive agreements to proceed.
FORECASTED EXPENDITURES
QUARTERS ENDING
--------------------------------------------------- NET TOTAL
JUNE 30, SEPTEMBER 30, DECEMBER 31, MARCH 31, FORECASTED
2004 2004 2004 2005 EXPENDITURES
-------- ------------- ------------ --------- ------------
(IN MILLIONS)
Net Forecasted Capital Project
Expenditures.................... $42 $11 $18 $10 $ 81
Other Forecasted Capital
Expenditures.................... 13 10 5 10 38
Additional Capital Contributions
to Our Unconsolidated
Affiliates...................... 11 8 3 -- 22
--- --- --- --- ----
Total Forecasted Expenditures..... $66 $29 $26 $20 $141
=== === === === ====
CONSTRUCTION PROJECTS
CAPITAL EXPENDITURES
-------------------------------------------------
AS OF CAPACITY
FORECASTED MARCH 31, 2004 --------------------
----------------------- ----------------------- NATURAL
TOTAL(1) GULFTERRA(2) TOTAL(1) GULFTERRA(2) OIL GAS EXPECTED IN-SERVICE
-------- ------------ -------- ------------ --------- -------- -------------------
(IN MILLIONS) (MBBLS/D) (MMCF/D)
Wholly owned projects
Marco Polo Natural Gas and Oil
Pipelines.................... $ 106 $ 89 $ 97 $ 80 120 400 Mid-Year 2004
Phoenix Gathering System....... 66 60 59 56 -- 450 Mid-Year 2004
Petal Conversion Project....... 17 17 -- -- -- 1.8(3) Fourth Quarter 2004
Joint venture projects
Marco Polo Tension Leg
Platform..................... 239 49 231 39 120 300 Second Quarter 2004
Cameron Highway Oil Pipeline... 464 95 386 85 500 -- Fourth Quarter 2004
- ---------------
(1) Includes 100 percent of costs and is not reduced for anticipated
contributions in aid of construction, project financings and contributions
from joint venture partners. We expect to receive $6.1 million (of which
$3.0 million has been collected as of March 31, 2004) from ANR Pipeline
Company for our Phoenix project. We have received $10.5 million from ANR
Pipeline Company and $7.0 million from El Paso Field Services for the Marco
Polo natural gas pipeline.
(2) GulfTerra expenditures are net of anticipated or received contributions in
aid of construction, project financings and contributions from joint venture
partners, to the extent applicable.
(3) Capacity in Bcf
PETAL CONVERSION PROJECT
We are planning, subject to final regulatory approval, to convert our
existing brine well at our propane storage caverns in Hattiesburg, Mississippi
to natural gas service. This conversion will cost approximately $17 million and
will create a new 1.8 Bcf working natural gas cavern that would be integrated
into our Petal natural gas storage facility. We are currently negotiating with
customers for contracts to subscribe the 1.8 Bcf capacity and expect to have the
cavern in service during the fourth quarter of 2004. We expect to fund the
conversion project costs through internally generated funds and borrowings under
our credit facility.
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $63.5 million for the quarter
ended March 31, 2004, compared to $71.4 million for the same period in 2003. The
decrease was primarily attributable to changes in working capital and lower
distributions from our unconsolidated affiliate, Poseidon, due to Poseidon's
37
construction of the Front Runner oil pipeline. This decrease was partially
offset by higher operating cash flows generated by our Texas intrastate pipeline
system, natural gas storage assets, and Falcon Nest platform.
CASH USED IN INVESTING ACTIVITIES
Net cash used in investing activities was approximately $53.5 million for
the quarter ended March 31, 2004. Our investing activities included capital
expenditures of $47.8 million primarily related to our Marco Polo pipelines,
Phoenix gathering system and the San Juan optimization project, as well as
maintenance expenditures primarily related to our Chaco plant, GulfTerra Texas
Intrastate system and our NGL pipeline systems. Our investing activities also
included additions to investments in unconsolidated affiliates of $5.8 million
related to additional equity contributions we made to Deepwater Gateway for the
construction of the Marco Polo TLP.
CASH USED IN FINANCING ACTIVITIES
Net cash used in financing activities was approximately $17.1 million for
the quarter ended March 31, 2004. During 2004, cash used in our financing
activities included repayments on our revolving credit facility, as well as
distributions to our partners. Cash provided by financing activities included
the proceeds received from the conversion of Series F1 convertible units into
common units, the proceeds received from the exercise of unit options and the
proceeds from borrowings under our revolving credit facility.
RESULTS OF OPERATIONS
Our business activities are segregated into four distinct operating
segments:
- Natural gas pipelines and plants;
- Oil and NGL logistics;
- Natural gas storage; and
- Platform services.
Operating revenues and expenses by segment include intersegment revenues
and expenses which are eliminated in consolidation. For a further discussion of
the individual segments, see Item 1., Financial Statements, Note 11. For the
past two years, inflation has not had a material effect on any of our financial
results.
SEGMENT RESULTS
We use performance cash flows (which we formerly referred to as EBITDA) to
evaluate the performance of our segments, determine how resources will be
allocated and develop strategic plans. We define performance cash flows as
earnings before interest, depreciation and amortization and other adjustments.
Historically our lenders and equity investors have viewed our performance cash
flows measure as an indication of our ability to generate sufficient cash to
meet debt obligations or to pay distributions. We believe that there has been a
shift in investors' evaluation regarding investments in MLPs and they now put as
much focus on the performance of an MLP investment as they do its ability to pay
distributions. For that reason, we disclose performance cash flows as a measure
of our segment's performance.
We believe performance cash flows is also useful to our investors because
it allows them to evaluate the effectiveness of our business segments from an
operational perspective, exclusive of the costs to finance those activities and
depreciation and amortization, neither of which are directly relevant to the
efficiency of those operations. This measurement may not be comparable to
measurements used by other companies and should not be used as a substitute for
net income or other performance measures.
38
A reconciliation of our segment performance cash flows to our net income is
as follows:
QUARTER ENDED
MARCH 31,
-------------------
2004 2003
-------- --------
(IN THOUSANDS)
Natural gas pipelines and plants............................ $ 82,013 $ 77,835
Oil and NGL logistics....................................... 7,468 11,600
Natural gas storage......................................... 9,061 7,001
Platform services........................................... 6,363 4,235
-------- --------
Segment performance cash flows............................ 104,905 100,671
Plus: Other, nonsegment results............................. 5,405 5,266
Earnings from unconsolidated affiliates............... 2,208 3,316
Cumulative effect of accounting change................ -- 1,690
Less: Interest and debt expense............................. 28,031 34,486
Loss due to write-off of unamortized debt issuance
costs..................................................... -- 3,762
Depreciation, depletion and amortization.............. 26,223 23,697
Cash distributions from unconsolidated affiliates..... 750 4,710
Minority interest..................................... (12) 33
Net cash payment received from El Paso Corporation.... 1,960 2,040
-------- --------
Net income.................................................. $ 55,566 $ 42,215
======== ========
39
NATURAL GAS PIPELINES AND PLANTS
QUARTER ENDED
MARCH 31,
-------------------------
2004 2003
----------- -----------
(IN THOUSANDS, EXCEPT FOR
VOLUMES)
Natural gas pipelines and plants revenue.................... $181,536 $197,227
Cost of natural gas and other products...................... (63,946) (89,796)
-------- --------
Natural gas pipelines and plants margin..................... 117,590 107,431
Operating expenses excluding depreciation, depletion, and
amortization.............................................. (36,414) (30,552)
Other income and cash distributions from unconsolidated
affiliates in excess of earnings(1)....................... 837 923
Minority interest........................................... -- 33
-------- --------
Performance cash flows...................................... $ 82,013 $ 77,835
======== ========
Volumes (MDth/d)
Texas Intrastate.......................................... 3,209 3,352
San Juan Gathering........................................ 1,247 1,130
Permian Basin Gathering................................... 295 320
HIOS...................................................... 743 751
Falcon Nest Pipeline(2)................................... 272 30
Viosca Knoll Gathering.................................... 640 688
Other natural gas pipelines............................... 520 518
Processing plants......................................... 721 810
-------- --------
Total volumes.......................................... 7,647 7,599
======== ========
- ---------------
(1) Earnings from unconsolidated affiliates for the quarters ended March 31,
2004 and 2003, were $534 thousand and $629 thousand.
(2) The Falcon Nest pipeline was placed in service in March 2003.
We provide natural gas gathering and transportation services for a fee.
Agreements with some customers of our pipelines require that we purchase natural
gas from them at the wellhead for an index price less an amount that compensates
us for gathering services after which we sell the natural gas into the open
market at points on our system at the same index price. Accordingly, under these
agreements, our operating revenues and costs of natural gas and other products
are impacted equally by changes in energy commodity prices, thus our margin for
these agreements reflects only the fee we received for gathering services. At
our Indian Basin processing facility, our revenues reflect the gross sales of
NGL we retain as a processing fee. Included in our cost of natural gas and other
products is the payment to the producers for the natural gas liquids we marketed
on their behalf. For these reasons, we feel that gross margin (revenue less cost
of natural gas and other products) provides a more accurate and meaningful basis
for analyzing operating results for this segment. Revenues at our Chaco
processing facility are representative of our processing fee.
During the latter half of 2002, we experienced a significant unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast region (and
these assets) in late September and early October of 2002. As of March 31, 2004,
we had recorded fuel differences of approximately $7.3 million, which is
included in other non-current assets. We are currently in discussions with the
FERC as well as our customers regarding the potential collection of some or all
of the fuel differences. At this time we are not able to determine what amount,
if any, may be collectible from our customers. Any amount we are unable to
resolve or collect from our customers will negatively impact the future results
of our natural gas pipelines and plants segment.
40
Quarter Ended March 31, 2004 Compared With Quarter Ended March 31, 2003
Natural gas pipelines and plants margin for the quarter ended March 31,
2004, was $10.2 million higher than in the same period in 2003. This increase
was primarily due to an $11.6 million increase in margin for our Texas
intrastate pipeline system, of which $5.5 million was attributable to the
revaluation of our natural gas imbalances, due to a lower imbalance position in
2004. In addition, our Texas intrastate pipeline system had a $2.1 million
increase in the base business in the first quarter of 2004 and an additional
$4.1 million increase associated with improved efficiencies on the pipeline
system over the same period in 2003. Margin also increased by $1.8 million
reflecting a full quarter of results from the Falcon Nest Pipeline, which went
into service in March 2003. Partially offsetting these increases was a $2.4
million decrease in margin at our Permian Basin gathering assets attributable to
increased fuel costs and an additional $1.4 million decrease in margin related
to lower volumes at our Indian Basin gas plant associated with colder
temperatures.
Operating expenses excluding depreciation, depletion and amortization for
the quarter ended March 31, 2004, were $5.9 million higher than the same period
in 2003 primarily due to timing considerations associated with our normal
recurring operating expenses and increased allocated administrative costs,
primarily merger related costs and directors and officers liability insurance.
OIL AND NGL LOGISTICS
QUARTER ENDED
MARCH 31,
-------------------------
2004 2003
----------- -----------
(IN THOUSANDS, EXCEPT FOR
VOLUMES)
Oil and NGL logistics revenues.............................. $ 15,188 $ 11,968
Cost of natural gas and other products...................... (960) --
-------- --------
Oil and NGL logistics margin................................ 14,228 11,968
Operating expenses excluding depreciation, depletion, and
amortization.............................................. (6,762) (4,330)
Other income and cash distributions from unconsolidated
affiliates in excess of earnings(1)....................... 2 3,962
-------- --------
Performance cash flows...................................... $ 7,468 $ 11,600
======== ========
Liquid Volumes (Bbls/d)
NGL Fractionation Plants.................................. 76,143 67,036
NGL Pipeline Systems...................................... 27,476 18,958
Allegheny Oil Pipeline.................................... 29,195 17,491
Typhoon Oil Pipeline...................................... 33,354 18,517
Unconsolidated affiliate
Poseidon Oil Pipeline(2)............................... 101,581 153,798
-------- --------
Total liquid volumes................................... 267,749 275,800
======== ========
- ----------
(1) Earnings from unconsolidated affiliates for the quarters ended March 31,
2004 and 2003, were $1,790 thousand and $2,687 thousand.
(2) Represents 100 percent of Poseidon volumes.
41
The majority of the earnings from the oil and NGL logistics segment are
generated from volume-based fees for providing transportation of oil and NGL and
fractionation of NGL. However, many of the agreements with the customers on our
oil pipelines require that we purchase oil from the customer at the inlet of our
pipeline for an index price, less an amount that compensates us for
transportation services, and resell the oil to the customer at the outlet of our
pipeline at the same index price. We record these transactions based on the net
amount billed to our customers resulting in these transactions reflecting a fee
for transportation services. For these reasons, we feel that gross margin
(revenue less cost of natural gas and other products) provides a more accurate
and meaningful basis for analyzing operating results for this segment.
Margin is driven by product pricing for both oil and NGLs and volumes. Both
oil and NGLs volumes are impacted by natural resource decline as well as
increases in new production. Volumes at our NGL fractionation plants are
significantly impacted by processing economics, which are driven by the
difference between natural gas prices and NGL prices.
Typhoon Oil Pipeline, a wholly owned subsidiary, has transportation
agreements with BHP and ChevronTexaco which provide that Typhoon Oil purchase
the oil produced at the inlet of its pipeline for an index price less an amount
that compensates Typhoon Oil for transportation services. At the outlet of its
pipeline, Typhoon Oil resells this oil back to these producers at the same index
price. As disclosed in our 2003 Annual Report on Form 10-K, as amended, we now
record revenue from these buy/sell transactions upon delivery of the oil based
on the net amount billed to the producers. For the quarter ended March 31, 2003,
we reduced by $48.8 million our revenues and cost of natural gas and other
products to conform to the current period presentation. This revision had no
effect on operating income, net income or partners' capital.
Quarter Ended March 31, 2004 Compared With Quarter Ended March 31, 2003
For the quarter ended March 31, 2004, margin was $2.3 million higher than
the same period in 2003. Margin attributable to our NGL pipeline systems was up
$1.4 million due to a 45 percent increase in volumes largely attributable to our
NGL pipeline being down for maintenance through the third quarter of 2003. In
addition, margin from our NGL fractionation plants increased $0.8 million due to
higher volumes resulting from improved processing economics at the plants in
2004.
Operating expenses excluding depreciation, depletion and amortization for
the quarter ended March 31, 2004, were $2.4 million higher than the same period
in 2003 primarily due to timing considerations associated with our normal
recurring operating expenses and increased allocated administrative costs,
primarily merger related costs and directors and officers liability insurance.
Other income and cash distributions from unconsolidated affiliates in
excess of earnings for the quarter ended March 31, 2004, declined $4.0 million.
In October 2003, Poseidon began withholding distributions to fund its capital
expenditures related to its Front Runner project. As a result, we did not
receive cash distributions from Poseidon during the quarter ended March 31,
2004, and we do not expect to receive any distributions from Poseidon until the
Front Runner project is complete.
42
NATURAL GAS STORAGE
QUARTER ENDED
MARCH 31,
---------------------
2004 2003
--------- ---------
(IN THOUSANDS, EXCEPT
FOR VOLUMES)
Natural gas storage revenue................................. $12,450 $11,698
Cost of natural gas......................................... 207 (1,561)
------- -------
Natural gas storage margin.................................. 12,657 10,137
Operating expenses excluding depreciation, depletion, and
amortization.............................................. (3,597) (3,136)
Other income and cash distributions from unconsolidated
affiliates in excess of earnings.......................... 13 --
Minority interest........................................... (12) --
------- -------
Performance cash flows...................................... $ 9,061 $ 7,001
======= =======
Firm storage (Bcf)
Average working gas capacity available.................... 13.5 13.5
Average firm subscription................................. 13.0 12.7
Average monthly commodity volumes(1)...................... 6.2 4.9
Interruptible storage (Bcf)
Contracted volumes........................................ 0.2 --
Average monthly commodity volumes(1)...................... 0.7 0.7
- ----------
(1) Combined injections and withdrawals volumes.
At our Petal and Hattiesburg natural gas storage facilities, we collect
fixed and variable fees for providing storage services, some of which is
generated from customers who have cashout provisions, calculated by reference to
a tariff-based index. We incur expenses, which are reflected as cost of natural
gas, as we maintain these volumetric imbalance receivables and payables, all of
which are valued at current gas prices. Cost of natural gas reflects the initial
imbalance and the monthly revaluation of these amounts based on the monthly
change in natural gas prices. For these reasons, we believe that gross margin
(revenue less cost of natural gas and other products) provides a more accurate
and meaningful basis for analyzing operating results for this segment.
43
Quarter Ended March 31, 2004 Compared with Quarter Ended March 31, 2003
For the quarter ended March 31, 2004, margin was $2.5 million higher than
the same period in 2003 primarily due to a $1.6 million increase in margin at
our Hattiesburg storage facility attributable to the impact that lower natural
gas prices in 2004 had on the revaluation of our gas storage imbalances. In
addition, margin was up an additional $0.9 million as a result of an increase in
interruptible storage services at our leased Wilson storage facility. Operating
expenses were flat period over period with no significant changes in the
components of operating expenses.
PLATFORM SERVICES
QUARTER ENDED
MARCH 31,
-------------------
2004 2003
-------- --------
(IN THOUSANDS,
EXCEPT FOR VOLUMES)
Platform services revenue from external customers........... $6,642 $4,382
Platform services intersegment revenue...................... 585 646
Operating expenses excluding depreciation, depletion, and
amortization.............................................. (863) (793)
Other income and cash distributions from unconsolidated
affiliates in excess of earnings.......................... (1) --
------ ------
Performance cash flows...................................... $6,363 $4,235
====== ======
Natural gas platform volumes (MDth/d)
East Cameron 373.......................................... 111 120
Garden Banks 72........................................... 5 27
Viosca Knoll 817.......................................... 5 6
Falcon Nest platform(1)................................... 264 30
------ ------
Total natural gas platform volumes..................... 385 183
====== ======
Oil platform volumes (Bbl/d)
East Cameron 373.......................................... 1,312 821
Garden Banks 72........................................... 826 1,031
Viosca Knoll 817.......................................... 2,133 1,990
Falcon Nest platform(1)................................... 808 121
------ ------
Total oil platform volumes............................. 5,079 3,963
====== ======
- ----------
(1) The Falcon Nest platform was placed in service in March 2003.
Our platform services segment generally earns revenue through demand fees
(regular payments made by customers using our platform services regardless of
volumes) and commodity charges (volume-based payments made by customers).
Contracts for platform services often include both demand fees and commodity
charges, but demand fees generally expire after a fixed period of time.
Quarter Ended March 31, 2004 Compared with Quarter Ended March 31, 2003
For the quarter ended March 31, 2004, performance cash flows were $2.1
million higher than in the same period in 2003. Revenues increased by $3.2
million due to a full quarter of results attributable to the Falcon Nest fixed
leg platform, which was placed in service in March 2003. This increase is
partially offset by lower revenues of $1.4 million from the East Cameron 373
platform resulting from lower demand fees. Operating expenses were flat period
over period with no significant changes in the components of operating expenses.
44
Marco Polo TLP
The Marco Polo TLP, which is owned by Deepwater Gateway L.L.C., our 50
percent owned joint venture with Cal Dive International, was installed in the
first quarter of 2004. First production and, thus, volumetric payments are
expected to begin in mid-2004. In April 2004, Deepwater Gateway began receiving
monthly demand revenues of $2.1 million.
In March 2004, Deepwater Gateway L.L.C. executed a binding memorandum of
understanding with Eni Petroleum Exploration Co. Inc, ConocoPhillips Company and
Union Oil Company of California for the processing of their 48 percent working
interest in the K2 Field production on the Marco Polo TLP. Anadarko's 52 percent
interest in the K2 Field was previously dedicated.
OTHER, NON-SEGMENT RESULTS
Our oil and natural gas production interests in the Garden Banks 72, Garden
Banks 117, Viosca Knoll 817 and West Delta 35 Blocks principally comprise the
non-segment activity. Production from these properties, except West Delta 35, is
gathered, transported, and processed through our pipeline systems and platform
facilities. Oil and natural gas production volumes are produced and sold to
various third parties at the market price. Revenue is recognized in the period
of production, all of which is sold to our customers. These revenues may be
impacted by market changes, hedging activities, and natural declines in
production reserves. We are reducing our oil and natural gas production
activities by not acquiring additional properties due to their higher risk
profile. Accordingly, our focus is to maximize the production from our existing
portfolio of oil and natural gas properties.
Also included in other, non-segment results are the quarterly payments we
received from El Paso Corporation in connection with the sale of our Gulf of
Mexico assets in January 2001. El Paso Corporation agreed to pay us $2.25
million per quarter through the fourth quarter of 2003 and $2 million in the
first quarter of 2004. As of March 31, 2004, all required payments had been
received and, as a result, future performance cash flows for other non-segment
activities will be lower compared to prior periods.
DEPRECIATION, DEPLETION, AND AMORTIZATION
Depreciation, depletion and amortization for the quarter ended March 31,
2004, was $2.5 million higher than the same period in 2003 primarily due to an
increase in depreciation expense of $1.2 million from assets placed in service
during 2003, primarily our communication assets placed in service in October
2003, Falcon Nest pipeline and platform placed in service in March 2003 and the
Viosca Knoll pipeline extension placed in service in December 2003, partially
offset by a decrease in depreciation expense of $0.5 million due to our revised
estimate for the depreciable life of the Chaco plant resulting from our exchange
transaction with El Paso Corporation in October 2003. Additionally, we had
increased depletion of $0.8 million resulting from the true-up of reserves based
on revised reserve estimates.
INTEREST AND DEBT EXPENSE
Interest and debt expense, net of capitalized interest, for the quarter
ended March 31, 2004, was approximately $6.5 million lower than the same period
in 2003. The decrease is primarily due to a lower weighted average outstanding
balance on our revolving credit facility and lower weighted average interest
rates on our revolving credit facility and senior secured term loan.
Additionally, interest and debt expense decreased as a result of the repayment
of our senior secured acquisition term loan during the first quarter of 2003,
the repayment of the GulfTerra Holding term loan during the third quarter of
2003 and the redemption of a portion of our senior subordinated notes in
December 2003.
Capitalized interest for the quarter ended March 31, 2004, was $3.7
million, representing an increase of $1.8 million from the quarter ended March
31, 2003. The increase is the result of higher expenditures related to our
construction projects, primarily the Marco Polo natural gas and oil pipelines
and the Phoenix gathering system.
45
LOSS DUE TO WRITE-OFF OF UNAMORTIZED DEBT ISSUANCE COSTS
In March 2003, we repaid our $237.5 million senior secured acquisition term
loan which was due in May 2004 and recognized a loss of $3.8 million related to
the write-off of unamortized debt issuance costs related to this loan.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
Our cumulative effect of accounting change for the quarter ended March 31,
2003, reflects our adoption of SFAS No. 143, Accounting for Asset Retirement
Obligations, on January 1, 2003.
COMMITMENTS AND CONTINGENCIES
See Item 1, Financial Statements, Note 9, which is incorporated herein by
reference.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
None.
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS
We have made statements in this document that constitute forward-looking
statements. These statements are subject to risks and uncertainties.
Forward-looking statements include information concerning possible or assumed
future results of operations. These statements may relate to information or
assumptions about:
- earnings per unit;
- capital and other expenditures;
- cash distributions;
- financing plans;
- capital structure;
- liquidity and cash flow;
- pending legal proceedings and claims, including environmental matters;
- future economic performance;
- operating income;
- cost savings;
- management's plans; and
- goals and objectives for future operations.
46
Important factors that could cause actual results to differ materially from
estimates or projections contained in forward-looking statements are described
in our Annual Report on Form 10-K, as amended, for the year ended December 31,
2003, and our other filings with the SEC. Where any forward-looking statement
includes a statement of the assumptions or bases underlying the forward-looking
statement, we caution that, while we believe these assumptions or bases to be
reasonable and made in good faith, assumed facts or bases almost always vary
from the actual results, and the differences between assumed facts or bases and
actual results can be material, depending upon the circumstances. Where, in any
forward-looking statement, we express an expectation or belief as to future
results, such expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. These
statements relate to analyses and other information which are based on forecasts
of future results and estimates of amounts not yet determinable. These
statements also relate to our future prospects, developments and business
strategies. These forward-looking statements are identified by their use of
terms and phrases such as "anticipate," "believe," "could," "estimate,"
"expect," "intend," "may," "plan," "predict," "project," "will," and similar
terms and phrases, including references to assumptions. These forward-looking
statements involve risks and uncertainties that may cause our actual future
activities and results of operations to be materially different from those
suggested or described.
These risks may also be specifically described in our Current Reports on
Form 8-K and other documents filed with the SEC. We undertake no obligation to
publicly update or revise any forward-looking statements, whether as a result of
new information or otherwise. If one or more of these risks or uncertainties
materialize, or if underlying assumptions prove incorrect, our actual results
may vary materially from those expected, estimated or projected.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information updates, and you should read it in conjunction with, our
quantitative and qualitative disclosures about market risks reported in our
Annual Report on Form 10-K, as amended, for the year ended December 31, 2003, in
addition to information presented in Items 1 and 2 of this Quarterly Report on
Form 10-Q.
A majority of our commodity purchases and sales, which relate to sales of
oil and natural gas associated with our production operations, purchases and
sales of natural gas associated with pipeline operations, sales of natural gas
liquids and purchases or sales of gas associated with our processing plants and
our gathering activities, are at spot market or forward market prices. We use
futures, forward contracts, and swaps to limit our exposure to fluctuations in
the commodity markets and allow for a fixed cash flow stream from these
activities.
We estimate the entire $13.3 million of unrealized losses included in
accumulated other comprehensive income at March 31, 2004, will be reclassified
from accumulated other comprehensive income as a reduction to earnings over the
next nine months. When our derivative financial instruments are settled, the
related amount in accumulated other comprehensive income is recorded in the
income statement in operating revenues, cost of natural gas and other products,
or interest and debt expense, depending on the item being hedged. The effect of
reclassifying these amounts to the income statement line items is recording our
earnings for the period related to the hedged items at the "hedged price" under
the derivative financial instruments.
In February and August 2003, we entered into derivative financial
instruments to continue to hedge our exposure during 2004 to changes in natural
gas prices relating to gathering activities in the San Juan Basin. The
derivatives are financial swaps on 30,000 MMBtu per day whereby we receive an
average fixed price of $4.23 per MMBtu and pay a floating price based on the San
Juan index. As of March 31, 2004, the fair value of these cash flow hedges was a
liability of $9.2 million, as the market price at that date was higher than the
hedge price. For the quarter ended March 31, 2004, we reclassified approximately
$1.7 million of unrealized accumulated loss related to these derivatives from
accumulated other comprehensive income as a decrease in revenue. No
ineffectiveness exists in this hedging relationship because all purchase and
sale prices are based on the same index and volumes as the hedge transaction.
47
During 2003, we entered into additional derivative financial instruments to
hedge a portion of our business' exposure to changes in NGL prices during 2004.
We entered into financial swaps for 6,000 barrels per day for the period from
August 2003 to September 2004. The average fixed price received is $0.47 per
gallon for 2004 while we pay a monthly average floating price based on the OPIS
average price for each month. As of March 31, 2004, the fair value of these cash
flow hedges was a liability of $4.1 million. For the quarter ended March 31,
2004, we reclassified approximately $2.1 million of unrealized accumulated loss
related to these derivatives from accumulated other comprehensive income to
earnings. No ineffectiveness exists in this hedging relationship because all
purchase and sales prices are based on the same index and volumes as the hedge
transaction.
In connection with our GulfTerra Intrastate Alabama operations, we have
fixed price contracts with specific customers for the sale of predetermined
volumes of natural gas for delivery over established periods of time. We entered
into cash flow hedges in 2003 to offset the risk of increasing natural gas
prices. For January and February 2004, we contracted to purchase 20,000 MMBtu
and for March 2004, we contracted to purchase 15,000 MMBtu. The average fixed
price paid during 2004 was $5.28 per MMBtu while we received a floating price
based on the SONAT-Louisiana index. As of March 31, 2004, these cash flow hedges
expired and we reclassified a gain of approximately $45 thousand from
accumulated other comprehensive income to earnings. No ineffectiveness existed
in this hedging relationship because all purchase and sale prices are based on
the same index and volumes as the hedge transaction.
In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million of our 8 1/2% senior subordinated notes
due 2011. With this swap agreement, we paid the counterparty a LIBOR based
interest rate plus a spread of 4.20% and received a fixed rate of 8 1/2%. We
accounted for this derivative as a fair value hedge under SFAS No. 133. In March
2004, we terminated our fixed to floating interest rate swap with our
counterparty. The value of the transaction at termination was zero, and as such,
neither we, nor our counterparty, were required to make any payments. Also,
neither we, nor our counterparty, have any future obligations under this
transaction.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Controls and Procedures. Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls over financial reporting (Internal Controls) as of the end
of the period covered by this Quarterly Report pursuant to Rules 13a-15 and
15d-15 under the Securities Exchange Act of 1934 (Exchange Act).
Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.
48
Limitations on the Effectiveness of Controls. Our management, including
the principal executive officer and principal financial officer, does not expect
that our Disclosure Controls and Internal Controls will prevent all errors and
all fraud. The design of a control system must reflect the fact that there are
resource constraints, and the benefits of controls must be considered relative
to their costs. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within the company have been detected. These
inherent limitations include the realities that judgments in decision-making can
be faulty, and that breakdowns can occur because of simple errors or mistakes.
Additionally, controls can be circumvented by the individual acts of some
persons, by collusion of two or more people, or by management override of the
controls. The design of any system of controls also is based in part upon
certain assumptions about the likelihood of future events. Therefore, a control
system, no matter how well conceived and operated, can provide only reasonable,
not absolute, assurance that the objectives of the control system are met. Our
Disclosure Controls and Internal Controls are designed to provide such
reasonable assurances of achieving our desired control objectives, and our
principal executive officer and principal financial officer have concluded that
our Disclosure Controls and Internal Controls are effective in achieving that
level of reasonable assurance.
No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
our Internal Controls, or whether we had identified any acts of fraud involving
personnel who have a significant role in our Internal Controls. This information
was important both for the controls evaluation generally and because the
principal executive officer and principal financial officer are required to
disclose that information to the Audit and Conflicts Committee of our general
partner's board of directors and our independent auditors and to report on
related matters in this section of the Quarterly Report. The principal executive
officer and principal financial officer note that there have not been any
significant changes in Internal Controls or in other factors that could
significantly affect Internal Controls, including any corrective actions with
regard to significant deficiencies and material weaknesses.
We are currently undergoing a comprehensive effort to ensure compliance
with Section 404 of the Sarbanes Oxley Act of 2002 for the year ended December
31, 2004. This effort includes internal control documentation and review under
the direction of senior management. During the course of these activities, we
have identified certain internal control issues which management believes need
to be improved. These control issues are, in large part, the result of our
increased size and complexity as a result of acquisitions and continued business
growth.
The review has not identified any significant deficiencies or material
weaknesses in internal control as defined by the Public Company Accounting and
Oversight Board. However, we have made improvements to our internal controls
over financial reporting as a result of our review efforts and will continue to
do so. These improvements include formalizing and communicating certain policies
and procedures, strengthening system security access and segregation of duties,
and increasing the frequency of monitoring controls.
Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to us and our consolidated subsidiaries is made known to our
management, including the principal executive officer and principal financial
officer, on a timely basis.
Officer Certifications. The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included as Exhibits to this Quarterly
Report.
49
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 9, which is incorporated
herein by reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Each exhibit identified below is filed as part of this document. Exhibits
not incorporated by reference to a prior filing are designated by a "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" represent a management
contract or compensatory plan or arrangement.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.A -- Merger Agreement, dated as of December 15, 2003, by and
among GulfTerra Energy Partners, L.P., GulfTerra Energy
Company, L.L.C., Enterprise Products Partners, L.P.,
Enterprise Products GP, LLC, and Enterprise Products
Management LLC (Exhibit 2.1 to our Current Report on Form
8-K filed December 15, 2003).
3.A -- Amended and Restated Certificate of Limited Partnership
dated February 14, 2002; Amendment dated April 30, 2003
(Exhibit 3.A.1 to our 2003 First Quarter Form 10-Q);
Amendment 2 dated July 25, 2003 (Exhibit 3.A.1 to our
2003 Second Quarter Form 10-Q).
3.A.1 -- Conformed Certificate of Limited Partnership (Exhibit
3.A.1 to our 2003 Third Quarter Form 10-Q).
3.B -- Second Amended and Restated Agreement of Limited
Partnership effective as of August 31, 2000 (Exhibit 3.B
to our Current Report on Form 8-K dated March 6, 2001);
First Amendment dated November 27, 2002 (Exhibit 3.B.1 to
our Current Report on Form 8-K dated December 11, 2002);
Second Amendment dated May 5, 2003 (Exhibit 3.B.2 to our
Current Report on Form 8-K dated May 13, 2003); Third
Amendment dated May 16, 2003 (Exhibit 3.B.3 to our
Current Report on 8-K dated May 16, 2003); Fourth
Amendment dated July 23, 2003 (Exhibit 3.B.1 to our 2003
Second Quarter Form 10-Q); Fifth Amendment dated August
21, 2003 (Exhibit 3.B.1 to our Current Report on Form 8-K
dated October 10, 2003).
3.B.1 -- Conformed Partnership Agreement (Exhibit 3.B.2 to our
Current Report on Form 8-K dated October 10, 2003).
50
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.D -- Indenture dated as of May 27, 1999 among GulfTerra Energy
Partners, L.P., GulfTerra Energy Finance Corporation, the
Subsidiary Guarantors and Chase Bank of Texas, as Trustee
(Exhibit 4.1 to our Registration Statement on Form S-4,
filed on June 24, 1999, File Nos. 333-81143 through
333-81143-17); First Supplemental Indenture dated as of
June 30, 1999 (Exhibit 4.2 to our Amendment No. 1 to
Registration Statement on Form S-4, filed August 27, 1999
File Nos. 333-81143 through 333-81143-17); Second
Supplemental Indenture dated as of July 27, 1999 (Exhibit
4.3 to our Amendment No. 1 to Registration Statement on
Form S-4, filed August 27, 1999, File Nos. 333-81143
through 333-81143-17); Third Supplemental Indenture dated
as of March 21, 2000, to the Indenture dated as of May
27, 1999, (Exhibit 4.7.1 to our 2000 Second Quarter Form
10-Q); Fourth Supplemental Indenture dated as of July 11,
2000 (Exhibit 4.2.1 to our 2001 Third Quarter Form 10-Q);
Fifth Supplemental Indenture dated as of August 30, 2000
(Exhibit 4.2.2 to our 2001 Third Quarter Form 10-Q);
Sixth Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.D.1 to our 2002 First Quarter Form 10-Q);
Seventh Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.D.2 to our 2002 First Quarter Form 10-Q);
Eighth Supplemental Indenture dated as of October 10,
2002 (Exhibit 4.D.3 to our 2002 Third Quarter Form 10-Q);
Ninth Supplemental Indenture dated as of November 27,
2002 (Exhibit 4.D.1 to our Current Report on Form 8-K
dated March 19, 2003); Tenth Supplemental Indenture dated
as of January 1, 2003 (Exhibit 4.D.2 to our Current
Report on Form 8-K dated March 19, 2003); Eleventh
Supplemental Indenture dated as of June 20, 2003 (Exhibit
4.D.1 to our 2003 Second Quarter Form 10-Q).
4.E -- Indenture dated as of May 17, 2001 among GulfTerra Energy
Partners, L.P., GulfTerra Energy Finance Corporation, The
Subsidiary Guarantors named therein and the Chase
Manhattan Bank, as Trustee (Exhibit 4.1 to our
Registration Statement on Form S-4 filed June 25, 2001,
Registration Nos. 333-63800 through 333-63800-20); First
Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.E.1 to our 2002 First Quarter Form 10-Q),
Second Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.E.2 to our 2002 First Quarter Form 10-Q);
Third Supplemental Indenture dated as of October 10, 2002
(Exhibit 4.E.3 to our 2002 Third Quarter Form 10-Q);
Fourth Supplemental Indenture dated as of November 27,
2002 (Exhibit 4.E.1 to our Current Report on Form 8-K
dated March 19, 2003); Fifth Supplemental Indenture dated
as of January 1, 2003 (Exhibit 4.E.2 to our Current
Report on Form 8-K dated March 19, 2003); Sixth
Supplemental Indenture dated as of June 20, 2003 (Exhibit
4.E.1 to our 2003 Second Quarter Form 10-Q).
4.G -- Registration Rights Agreement by and between El Paso
Corporation and GulfTerra Energy Partners, L.P. dated as
of November 27, 2002 (Exhibit 4.G to our Current Report
on Form 8-K dated December 11, 2002).
4.I -- Indenture dated as of November 27, 2002 by and among
GulfTerra Energy Partners, L.P., GulfTerra Energy Finance
Corporation, the Subsidiary Guarantors named therein and
JPMorgan Chase Bank, as Trustee (Exhibit 4.I to our
Current Report on Form 8-K dated December 11, 2002);
First Supplemental Indenture dated as of January 1, 2003
(Exhibit 4.I.1 to our Current Report on Form 8-K dated
March 19, 2003). Second Supplemental Indenture dated as
of June 20, 2003 (Exhibit 4.I.1 to our 2003 Second
Quarter Form 10-Q).
51
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.K -- Indenture dated as of March 24, 2003 by and among
GulfTerra Energy Partners, L.P., GulfTerra Energy Finance
Corporation, the Subsidiary Guarantors named therein and
JPMorgan Chase Bank, as Trustee dated as of March 24,
2003 (Exhibit 4.K to our Quarterly Report on Form 10-Q
dated May 15, 2003), First Supplemental Indenture dated
as of June 20, 2003 (Exhibit 4.K.1 to our 2003 Second
Quarter Form 10-Q).
4.L -- Indenture dated as of July 3, 2003, by and among
GulfTerra Energy Partners, L.P., GulfTerra Energy Finance
Corporation, the Subsidiary Guarantors named therein and
Wells Fargo Bank, National Association, as Trustee
(Exhibit 4.L to our 2003 Second Quarter Form 10-Q).
4.M -- Unitholder Agreement dated May 16, 2003 by and between
GulfTerra Energy Partners, L.P. and Fletcher
International, Inc. (Exhibit 4.L to our Current Report on
Form 8-K filed May 19, 2003).
4.N -- Exchange and Registration Rights Agreement by and among
GulfTerra Energy Company, L.L.C., GulfTerra Energy
Partners, L.P. and Goldman Sachs & Co. dated as of
October 2, 2003 (Exhibit 10.U to our Current Report on
Form 8-K dated October 10, 2003).
*31.A -- Certification of Chief Executive Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
*31.B -- Certification of Chief Financial Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
*32.A -- Certification of Chief Executive Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
*32.B -- Certification of Chief Financial Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
UNDERTAKING
We hereby undertake, pursuant to Regulation S-K Items 601(b), paragraph
(4)(iii), to furnish to the U.S. Securities and Exchange Commission, upon
request, all constituent instruments defining the rights of holders of our
long-term debt not filed herewith for the reason that the total amount of
securities authorized under any such instruments does not exceed 10 percent of
our total consolidated assets.
(b) Reports on Form 8-K
We filed a Current Report on Form 8-K dated February 3, 2004 to announce an
overview of our merger with Enterprise.
We filed a Current Report on Form 8-K dated February 11, 2004 to announce
William G. Manias has assumed the position of Chief Financial Officer.
We filed a Current Report on Form 8-K dated April 20, 2004 to announce
Enterprise and El Paso Corporation amended their agreement with regard to their
ownership of the merged companies' general partner upon completion of the
merger.
We filed a Current Report on Form 8-K dated May 5, 2004 to notify our
unitholders and the market that we have identified a potential revision to the
accounting for the cash settlement of natural gas imbalance receivables on our
Texas Intrastate pipeline system, which we acquired in April 2002.
We filed a Current Report on Form 8-K dated May 7, 2004 to file the one
year audited balance sheet of GulfTerra Energy Company, L.L.C. our general
partner, as of December 31, 2003, which is incorporated by reference into our
Registration Statement on Form S-3 (No. 333-81772, No. 333-85987, No. 333-107082
and No. 333-110116) and on Form S-8 (No. 333-70617).
52
We also furnished to the SEC Current Reports on Form 8-K under Item 9 and
Item 12. Current Reports on Form 8-K under Item 9 and Item 12 are not considered
to be "filed" for purposes of Section 18 of the Securities and Exchange Act of
1934 and are not subject to the liabilities of that section.
53
SIGNATURES
Pursuant to the requirements 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.
GULFTERRA ENERGY PARTNERS, L.P.
Date: May 10, 2004 By: /s/ WILLIAM G. MANIAS
------------------------------------
William G. Manias
Vice President and Chief Financial
Officer
(Principal Financial Officer)
Date: May 10, 2004 By: /s/ KATHY A. WELCH
------------------------------------
Kathy A. Welch
Vice President and Controller
(Principal Accounting Officer)
54
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.A -- Merger Agreement, dated as of December 15, 2003, by and
among GulfTerra Energy Partners, L.P., GulfTerra Energy
Company, L.L.C., Enterprise Products Partners, L.P.,
Enterprise Products GP, LLC, and Enterprise Products
Management LLC (Exhibit 2.1 to our Current Report on Form
8-K filed December 15, 2003).
3.A -- Amended and Restated Certificate of Limited Partnership
dated February 14, 2002; Amendment dated April 30, 2003
(Exhibit 3.A.1 to our 2003 First Quarter Form 10-Q);
Amendment 2 dated July 25, 2003 (Exhibit 3.A.1 to our
2003 Second Quarter Form 10-Q).
3.A.1 -- Conformed Certificate of Limited Partnership (Exhibit
3.A.1 to our 2003 Third Quarter Form 10-Q).
3.B -- Second Amended and Restated Agreement of Limited
Partnership effective as of August 31, 2000 (Exhibit 3.B
to our Current Report on Form 8-K dated March 6, 2001);
First Amendment dated November 27, 2002 (Exhibit 3.B.1 to
our Current Report on Form 8-K dated December 11, 2002);
Second Amendment dated May 5, 2003 (Exhibit 3.B.2 to our
Current Report on Form 8-K dated May 13, 2003); Third
Amendment dated May 16, 2003 (Exhibit 3.B.3 to our
Current Report on 8-K dated May 16, 2003); Fourth
Amendment dated July 23, 2003 (Exhibit 3.B.1 to our 2003
Second Quarter Form 10-Q); Fifth Amendment dated August
21, 2003 (Exhibit 3.B.1 to our Current Report on Form 8-K
dated October 10, 2003).
3.B.1 -- Conformed Partnership Agreement (Exhibit 3.B.2 to our
Current Report on Form 8-K dated October 10, 2003).
4.D -- Indenture dated as of May 27, 1999 among GulfTerra Energy
Partners, L.P., GulfTerra Energy Finance Corporation, the
Subsidiary Guarantors and Chase Bank of Texas, as Trustee
(Exhibit 4.1 to our Registration Statement on Form S-4,
filed on June 24, 1999, File Nos. 333-81143 through
333-81143-17); First Supplemental Indenture dated as of
June 30, 1999 (Exhibit 4.2 to our Amendment No. 1 to
Registration Statement on Form S-4, filed August 27, 1999
File Nos. 333-81143 through 333-81143-17); Second
Supplemental Indenture dated as of July 27, 1999 (Exhibit
4.3 to our Amendment No. 1 to Registration Statement on
Form S-4, filed August 27, 1999, File Nos. 333-81143
through 333-81143-17); Third Supplemental Indenture dated
as of March 21, 2000, to the Indenture dated as of May
27, 1999, (Exhibit 4.7.1 to our 2000 Second Quarter Form
10-Q); Fourth Supplemental Indenture dated as of July 11,
2000 (Exhibit 4.2.1 to our 2001 Third Quarter Form 10-Q);
Fifth Supplemental Indenture dated as of August 30, 2000
(Exhibit 4.2.2 to our 2001 Third Quarter Form 10-Q);
Sixth Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.D.1 to our 2002 First Quarter Form 10-Q);
Seventh Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.D.2 to our 2002 First Quarter Form 10-Q);
Eighth Supplemental Indenture dated as of October 10,
2002 (Exhibit 4.D.3 to our 2002 Third Quarter Form 10-Q);
Ninth Supplemental Indenture dated as of November 27,
2002 (Exhibit 4.D.1 to our Current Report on Form 8-K
dated March 19, 2003); Tenth Supplemental Indenture dated
as of January 1, 2003 (Exhibit 4.D.2 to our Current
Report on Form 8-K dated March 19, 2003); Eleventh
Supplemental Indenture dated as of June 20, 2003 (Exhibit
4.D.1 to our 2003 Second Quarter Form 10-Q).
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.E -- Indenture dated as of May 17, 2001 among GulfTerra Energy
Partners, L.P., GulfTerra Energy Finance Corporation, The
Subsidiary Guarantors named therein and the Chase
Manhattan Bank, as Trustee (Exhibit 4.1 to our
Registration Statement on Form S-4 filed June 25, 2001,
Registration Nos. 333-63800 through 333-63800-20); First
Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.E.1 to our 2002 First Quarter Form 10-Q),
Second Supplemental Indenture dated as of April 18, 2002
(Exhibit 4.E.2 to our 2002 First Quarter Form 10-Q);
Third Supplemental Indenture dated as of October 10, 2002
(Exhibit 4.E.3 to our 2002 Third Quarter Form 10-Q);
Fourth Supplemental Indenture dated as of November 27,
2002 (Exhibit 4.E.1 to our Current Report on Form 8-K
dated March 19, 2003); Fifth Supplemental Indenture dated
as of January 1, 2003 (Exhibit 4.E.2 to our Current
Report on Form 8-K dated March 19, 2003); Sixth
Supplemental Indenture dated as of June 20, 2003 (Exhibit
4.E.1 to our 2003 Second Quarter Form 10-Q).
4.G -- Registration Rights Agreement by and between El Paso
Corporation and GulfTerra Energy Partners, L.P. dated as
of November 27, 2002 (Exhibit 4.G to our Current Report
on Form 8-K dated December 11, 2002).
4.I -- Indenture dated as of November 27, 2002 by and among
GulfTerra Energy Partners, L.P., GulfTerra Energy Finance
Corporation, the Subsidiary Guarantors named therein and
JPMorgan Chase Bank, as Trustee (Exhibit 4.I to our
Current Report on Form 8-K dated December 11, 2002);
First Supplemental Indenture dated as of January 1, 2003
(Exhibit 4.I.1 to our Current Report on Form 8-K dated
March 19, 2003). Second Supplemental Indenture dated as
of June 20, 2003 (Exhibit 4.I.1 to our 2003 Second
Quarter Form 10-Q).
4.K -- Indenture dated as of March 24, 2003 by and among
GulfTerra Energy Partners, L.P., GulfTerra Energy Finance
Corporation, the Subsidiary Guarantors named therein and
JPMorgan Chase Bank, as Trustee dated as of March 24,
2003 (Exhibit 4.K to our Quarterly Report on Form 10-Q
dated May 15, 2003), First Supplemental Indenture dated
as of June 20, 2003 (Exhibit 4.K.1 to our 2003 Second
Quarter Form 10-Q).
4.L -- Indenture dated as of July 3, 2003, by and among
GulfTerra Energy Partners, L.P., GulfTerra Energy Finance
Corporation, the Subsidiary Guarantors named therein and
Wells Fargo Bank, National Association, as Trustee
(Exhibit 4.L to our 2003 Second Quarter Form 10-Q).
4.M -- Unitholder Agreement dated May 16, 2003 by and between
GulfTerra Energy Partners, L.P. and Fletcher
International, Inc. (Exhibit 4.L to our Current Report on
Form 8-K filed May 19, 2003).
4.N -- Exchange and Registration Rights Agreement by and among
GulfTerra Energy Company, L.L.C., GulfTerra Energy
Partners, L.P. and Goldman Sachs & Co. dated as of
October 2, 2003 (Exhibit 10.U to our Current Report on
Form 8-K dated October 10, 2003).
*31.A -- Certification of Chief Executive Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
*31.B -- Certification of Chief Financial Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
*32.A -- Certification of Chief Executive Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
*32.B -- Certification of Chief Financial Officer, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
EXHIBIT 31.A
CERTIFICATION
I, Robert G. Phillips, certify that:
1. I have reviewed this quarterly report on Form 10-Q of GulfTerra Energy
Partners, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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 quarterly report;
4. The registrant's other certifying officer(s) 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)) 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) 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
(c) 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(s) and I have disclosed, based
on our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
control over financial reporting.
Date: May 10, 2004
/s/ ROBERT G. PHILLIPS
--------------------------------------
Robert G. Phillips
Chairman of the Board and Chief
Executive Officer
(Principal Executive Officer)
GulfTerra Energy Partners, L.P.
EXHIBIT 31.B
CERTIFICATION
I, William G. Manias, certify that:
1. I have reviewed this quarterly report on Form 10-Q of GulfTerra Energy
Partners, L.P.;
2. Based on my knowledge, this quarterly 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 quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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 quarterly report;
4. The registrant's other certifying officer(s) 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)) 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) 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
(c) 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(s) and I have disclosed, based
on our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
control over financial reporting.
Date: May 10, 2004
/s/ WILLIAM G. MANIAS
--------------------------------------
William G. Manias
Vice President and Chief Financial
Officer
(Principal Financial Officer)
GulfTerra Energy Partners, L.P.
EXHIBIT 32.A
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 on Form 10-Q for the period ending
March 31, 2004, of GulfTerra Energy Partners, L.P. (the "Company") as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I,
Robert G. Phillips, Chairman of the Board and Chief Executive Officer certify
(i) that the Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
/s/ ROBERT G. PHILLIPS
--------------------------------------
Robert G. Phillips
Chairman of the Board and Chief
Executive Officer
(Principal Executive Officer)
May 10, 2004
A signed original of this written statement required by Section 906 has
been provided to GulfTerra Energy Partners, L.P., and will be retained by
GulfTerra Energy Partners, L.P. and furnished to the Securities and Exchange
Commission or its staff upon request.
EXHIBIT 32.B
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 on Form 10-Q for the period ending
March 31, 2004, of GulfTerra Energy Partners, L.P. (the "Company") as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I,
William G. Manias, Vice President and Chief Financial Officer certify (i) that
the Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended, and (ii) that the information
contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
/s/ WILLIAM G. MANIAS
--------------------------------------
William G. Manias
Vice President and Chief Financial
Officer
(Principal Financial Officer)
May 10, 2004
A signed original of this written statement required by Section 906 has
been provided to GulfTerra Energy Partners, L.P., and will be retained by
GulfTerra Energy Partners, L.P. and furnished to the Securities and Exchange
Commission or its staff upon request.
