GULFTERRA ENERGY PARTNERS L P - 10-Q Quarterly Report

Back to GetFilings.com

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

----------

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 JUNE 30, 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 59,964,566 common units outstanding as of August 6,
2004.

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

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)

- ---------------

(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)

See accompanying notes.

2

GULFTERRA ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

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

ACCUMULATED OTHER COMPREHENSIVE LOSS

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
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. References to "us", "we",
"our", or "GulfTerra" are intended to mean the consolidated business and
operations of GulfTerra Energy Partners, L.P.

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 June 30, 2004,
and for the quarters and six months ended June 30, 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 June 30, 2004 and December 31, 2003, we had included in accounts
receivable, net on our balance sheets, unbilled trade receivables of $74.6
million and $63.1 million. Also, as of June 30, 2004 and December 31, 2003, we
had included in accounts payable on our balance sheets, accrued gas purchase
costs of $20.0 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 June 30,
2004 and December 31, 2003, our allowance was $4.0 million.
- ---------------

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 and six months ended
June 30, 2003, we reduced by $73.1 million and $121.9 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 and six months ended June 30, 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.
Compensation expense for the quarter and six months ended June 30, 2004 and 2003
is reflected in the table below for our stock-based compensation programs
accounted for under the provisions of SFAS No. 123.

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:

The effects of applying the provisions of SFAS No. 123 in this pro forma
disclosure for all of our stock-based compensation programs 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.

6

Inventory

In June 2004, we purchased pipeline inventory, consisting of parts and
materials, from El Paso Natural Gas Company (EPNG); see Note 8, Related Party
Transactions, for further discussion. This inventory is included on our balance
sheet as of June 30, 2004, in other current assets. We use the average cost
method to account for our inventory and we value our inventory at the lower of
its cost or market value.

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.

Two-Class Method of Computing Earnings per Common Unit

During the second quarter of 2004, we adopted the provisions of Emerging
Issues Task Force (EITF) 03-6, Participating Securities and the Two-Class Method
under SFAS No. 128. EITF 03-6 requires the use of the two-class method of
determining basic earnings per unit. Under the two-class method, distributions
to equity owners are subtracted from earnings, and any remaining earnings would
be allocated to the various classes of owners in proportion to their right to
receive distributions as if those earnings had been distributed. The total of
distributions to each class of owner plus the amount allocated to each class
would be used to compute earnings per unit for that class. Because our
distributions to owners exceeded earnings during the periods presented, as has
historically been the case, the two-class method did not produce any change in
result from the way we have traditionally computed earnings per unit. As a
result, the adoption of this standard had no effect on our earnings per unit
calculation for the quarters and six months ended June 30, 2004 and 2003.

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
$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; and

- 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.

On June 22, 2004, Enterprise's registration statement on Form S-4 was
declared effective by the SEC. On July 29, 2004, our common and Series C
unitholders approved the adoption of the merger agreement to
7

combine us with a wholly-owned subsidiary of Enterprise. See Part II, Other
Information, Item 4. Submission of Matters to a Vote of Security Holders, for
the results of the unitholder vote. We expect the completion of the merger to
occur in the third quarter of 2004, although it remains subject to review by the
Federal Trade Commission (FTC) and the satisfaction of other conditions to
close.

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. In March 2004, we recorded a liability and a related
deferred charge of $4.3 million, which was 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
charge 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 and six months ended June 30, 2004,
we amortized $2.2 million and $2.8 million to expense. As of June 30, 2004, the
remaining deferred charge was $1.5 million. 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. During the quarter and six months ended June 30, 2004,
we recognized expenses for legal and audit fees totaling $1.4 million and $1.5
million associated with 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. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

- ---------------

(1) Includes leasehold acquisition costs with an unamortized balance of $2.1
million and $3.2 million at June 30, 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.

8

4. 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.
To avoid a default, our credit facility must be refinanced or amended at or
before the closing of the merger. Enterprise has stated that it currently
intends that our credit facility be refinanced before the closing of the merger
and that, if that does not occur, there are reasonable grounds to believe that
our existing credit facility will be amended prior to the closing of the merger.
If the facility is not amended or refinanced prior to closing, the resulting
default would have a material adverse effect on the combined company. In
addition, the closing of the merger 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 closing. In coordination with Enterprise, we
are evaluating alternative financing plans in preparation for the closing of the
merger. On August 4, 2004, Enterprise announced that one of its subsidiaries
commenced cash tender offers to purchase any and all of our outstanding senior
subordinated and senior notes. In connection with the tender offers, Enterprise
is soliciting consents to proposed amendments that would eliminate certain
restrictive covenants and default provisions contained in the indentures
governing the notes. Enterprise is commencing the tender offers and consent
solicitations in anticipation of completing the merger, and the merger is a non-
waivable condition to the completion of the tender offers and consent
solicitations. We and Enterprise can agree on the date of the merger closing
after the receipt of all necessary approvals. We do not intend to close until
appropriate financing or other arrangements are in place.

CREDIT FACILITY

As of June 30, 2004, our credit facility consisted of three parts: the
revolving credit facility maturing in 2006, a senior secured term loan maturing
in 2007 and a senior secured term loan maturing in 2008. Our credit facility is
guaranteed by us and each of our subsidiaries, excluding 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 Standard & Poor's (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 June 30, 2004, we had $462 million outstanding under our revolving
credit facility at an average interest rate of 3.16%. We may elect that all or a
portion of the revolving credit facility bear interest at either the variable
base rate described above increased by 1.0% or LIBOR increased by 2.0%. The
amount available to us at June 30, 2004, under this facility was $218 million.

9

Senior Secured Term Loans

In May 2004, we obtained an additional $200 million senior secured term
loan in addition to our already existing $300 million senior secured term loan.
We initially used this additional $200 million to temporarily reduce
indebtedness under our $700 million revolving credit facility and subsequently
to fund the redemption of our $175 million aggregate principal amount of 10 3/8%
senior subordinated notes due 2009. Our new senior secured term loan, which we
may prepay in full at any time, is payable in semi-annual installments of $1.0
million in November and May of each year for the first six installments, and the
remaining balance is due at maturity in October 2007. Our already-existing
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 is due at maturity in December 2008. On both senior secured
term loans, we may elect that all or a portion of the senior secured term loans
bear interest at either 1.25% over the variable base rate described above or
LIBOR increased by 2.25%. As of June 30, 2004, we had $498.5 million outstanding
on our senior secured term loans with an average interest rate of 3.65%.

LONG-TERM DEBT

In April 2004, we redeemed, at a premium, approximately $39.1 million in
principal amount of our 8 1/2% senior subordinated notes due June 2010. In
connection with the redemption of the notes, we recognized additional expense
during the quarter ended June 30, 2004, totaling $4.1 million resulting from the
payment of the redemption premium and the write-off of unamortized debt issuance
costs.

In June 2004, we redeemed all of our outstanding $175 million aggregate
principal amount of 10 3/8% senior subordinated notes due 2009. The notes were
redeemed at a redemption price of 105.2% of the principal amount, plus accrued
and unpaid interest up to June 1, 2004. In connection with the redemption of the
notes, we recognized additional expense during the quarter ended June 30, 2004,
totaling $12.2 million resulting from the payment of the redemption premium and
the write-off of unamortized debt issuance costs.

We accounted for the costs on both redemptions in accordance with the
provisions of SFAS No. 145, Rescission of Financial Accounting Standards Board
(FASB) Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections.

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 more balanced 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 was 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.

10

INDUSTRIAL DEVELOPMENT 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 million in Industrial Development
Revenue Bonds to GulfTerra Field Services, L.L.C., our direct, wholly-owned
subsidiary. 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. We have netted the
loan amount and the bond amount of $52 million and the interest payable and
interest receivable amount of $0.6 million on our balance sheet as of June 30,
2004. We have also netted the interest expense and interest income amount of
$0.6 million on our income statements for the quarter and six months ended June
30, 2004. Our presentation of the Industrial Development Revenue Bonds is
reflected in accordance with the provisions of FIN No. 39, Offsetting of Amounts
Related to Certain Contracts, and SFAS No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities, since we have
the ability and intent to offset these items.

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 June 30, 2004, Poseidon had $111 million outstanding with an average interest
rate of 3.47%.

Poseidon's credit agreement contains covenants such as restrictions on debt
levels, liens, mergers, the sales of assets and dividends 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, an unconsolidated affiliate in which we have a 50
percent joint venture interest and that constructed 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. Construction of the Marco Polo TLP was
completed during the first quarter of 2004, and in June 2004, Deepwater Gateway
converted the project finance loan into a term loan with a final maturity date
of June 2009. The term loan is payable in twenty equal quarterly installments of
$5.5 million beginning September 30, 2004, and the remaining outstanding
principal of $45 million is due on the maturity date in June 2009. 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 term 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 June 30, 2004, Deepwater Gateway had $155 million
outstanding under the term loan at an average interest rate of 3.15% and had not
paid us or any of our subsidiaries any distributions.

11

Cameron Highway

Cameron Highway Oil Pipeline Company (Cameron Highway), 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.

The construction loan bears interest at a variable rate. Upon completion of
the construction, which is expected during the fourth quarter of 2004, 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 $8.1 million, with the remaining unpaid
principal amount payable on the maturity date. If the construction loan fails to
convert into a term loan by January 2006, the construction loan and senior
secured notes become fully due and payable. At June 30, 2004, Cameron Highway
had $171 million outstanding under the construction loan at an average interest
rate of 4.56%.

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 June 30, 2004, Cameron
Highway had $100 million outstanding under the senior secured notes at an
average interest rate of 7.36%.

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 June 30, 2004 (in thousands):

2004........................................................ $ 2,500
2005........................................................ 5,000
2006........................................................ 467,000
2007........................................................ 198,000
2008........................................................ 288,000
Thereafter.................................................. 921,515
----------
Total long-term debt and other financing obligations,
including current maturities........................... $1,882,015
==========

LOSS DUE TO EARLY REDEMPTIONS OF DEBT

We recognized losses associated with early redemptions of debt as follows
(in thousands):

12

5. 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:

SIX MONTHS ENDED JUNE 30, 2004
(IN THOUSANDS)

SIX MONTHS ENDED JUNE 30, 2003
(IN THOUSANDS)

- ----------

(1) The Marco Polo TLP, which is owned by Deepwater Gateway L.L.C., was
installed in the first quarter of 2004. First production and thus volumetric
payments started in July 2004. In April 2004, Deepwater Gateway began
receiving monthly demand payments of $2.1 million. Prior to the TLP
installation, Deepwater Gateway was a development stage company; therefore
there were no operating revenues or operating expenses. However, it did
incur organizational expenses and received interest income.

(2) Cameron Highway Oil Pipeline Company is a development stage company;
therefore there are no operating revenues or operating expenses. Since its
formation in June 2003, it has incurred organizational expenses and received
interest income.

(3) 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.

(4) 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.

13

6. PARTNERS' CAPITAL

Cash distributions

The following table reflects our per unit cash distributions to our common
unitholders and the total distributions paid to our common unitholders, Series C
unitholder and general partner during the six months ended June 30, 2004:

In July 2004, we declared a cash distribution of $0.71 per common unit and
Series C unit, $50.3 million in the aggregate, for the quarter ended June 30,
2004, which we will pay on August 13, 2004, to holders of record as of July 30,
2004. Also in August 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.

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
June 30, 2004 and August 5, 2004, was $38.47 and $37.10 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 June 30, 2004, and is included in partners' capital as a component of common
units capital.

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
June 30, 2004 and December 31, 2003.

In July 2004, 10 Series F1 convertible units were converted into 261,437
common units, for which the holder of the convertible units paid us $10 million.
Additionally, our general partner contributed to us $0.1 million in cash in
order to maintain its one percent general partner interest.

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 $0.4 million
in cash in order to maintain its one percent general partner interest.

14

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

During the quarter ended June 30, 2004, we granted 4,962 restricted units
at a fair value per unit of $38.31 and 8,000 unit options with a grant price of
$38.31 to non-employee directors of our Board of Directors under our Director
Plan. We accounted for the restricted units in accordance with SFAS No. 123.
Under SFAS No. 123, the fair value of these issuances is reflected as deferred
compensation and is amortized to compensation expense over the period of
service, which we have estimated to be one year. The unit options issued have
been accounted for in accordance with APB No. 25. As these options were issued
at market value, under the provisions of APB No. 25, no entries were made at the
issuance date.

Total unamortized deferred compensation as of June 30, 2004 and December
31, 2003, was approximately $1.2 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.

Net proceeds from unit options exercised during the quarter and six months
ended June 30, 2004, were approximately $0.3 million and $4.9 million. Net
proceeds from unit options exercised during the quarter and six months ended
June 30, 2003, were $0.5 million.

At the close of the merger, any outstanding restricted units issued to (1)
employees of El Paso Field Services who will become employees of Enterprise or
(2) non-employee directors of our general partner's Board of Directors who will
be a member of the Board of Directors of the merged company will convert to
Enterprise common units with the same terms, except that the number of
Enterprise common units will be adjusted based on the 1.81 exchange ratio. Any
outstanding restricted units issued to employees of El Paso Field Services who
will not be employees of Enterprise or to non-employee directors of our general
partner's Board of Directors who will not be a member of the Board of Directors
of the merged company will vest on the merger date and be exchanged for
Enterprise common units at the 1.81 exchange ratio.

Unit Option Buyout

Under the merger agreement with Enterprise, we are obligated to repurchase,
at reasonable prices, before the effective time of the merger, all outstanding
employee and director unit options that have not been exercised or otherwise
canceled. Approximately 1,000,000 common unit options were outstanding at June
30, 2004, held by 28 current and former employees and directors. Since we do not
have the right under our option plan to force our option holders to sell their
options, we were required to negotiate a separate option purchase agreement
individually with each option holder. The governance and compensation committee
of our general partner's board of directors engaged an independent financial
advisor to assist in the determination of the appropriate repurchase prices for
the outstanding options. Subsequent to June 30, 2004, we entered into option
purchase agreements with all the option holders under which we have agreed to
purchase for cash and/or common units, and the option holders have agreed to
sell, any options that remain outstanding on the merger closing date for a
negotiated price. Each option purchase agreement permits the option holder to
exercise any or all of his or her options at any time and from time to time
prior to the merger closing. Based on information provided by the financial
advisor engaged by the governance and compensation committee, we estimate the
value, in the aggregate, of the outstanding options to be repurchased is
approximately $13 million.

15

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):

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 June 30, 2004
and 2003, were approximately 17 percent and 15 percent of our total revenue.
Revenues received from related parties for the six months ended June 30, 2004
and 2003, were approximately 17 percent and 14 percent of our total revenue.

Our transactions with related parties and affiliates are as follows:

16

The following table provides summary data categorized by our related
parties:

17

Our accounts receivable due from related parties consisted of the following
as of:

Our accounts payable due to related parties consisted of the following as
of:

18

Other Matters

Pipeline Inventory Purchase. In June 2004, we executed an agreement with
EPNG, a subsidiary of El Paso Corporation, for the purchase of certain parts and
materials inventory. We paid approximately $2.1 million for the items purchased
and this inventory is included on our balance sheet as of June 30, 2004, in
other current assets.

Petal. In September 2003, Petal entered into a nonbinding letter of intent
with Southern Natural Gas Company, a subsidiary of El Paso Corporation,
regarding the proposed development and sale of a natural gas storage cavern, and
the proposed sale of an undivided interest in the Petal pipeline and other
facilities related to that natural gas storage cavern. The new storage cavern
would be located at our storage complex near Hattiesburg, Mississippi. In June
2004, Petal and Southern Natural Gas Company terminated their letter of intent
and Petal announced that it would hold a nonbinding open season to determine
market interest for up to 5.0 Bcf of firm natural gas storage capacity, and up
to 500,000 MMBtu/d of firm transportation on the Petal pipeline, all available
in the third quarter of 2007.

Copper Eagle. In August 2003, Arizona Gas Storage, L.L.C., along with its
50 percent partner APACS Holdings L.L.C., sold their interest in Copper Eagle
Gas Storage L.L.C. to EPNG. Copper Eagle Gas Storage is developing a natural gas
storage project located outside of Phoenix, Arizona. Arizona Gas Storage, L.L.C.
is an indirect 60 percent owned subsidiary of us and 40 percent owned by
IntraGas US, a Gaz de France North American subsidiary. APACS Holdings L.L.C. is
a wholly owned subsidiary of Pinnacle West Energy, a subsidiary of Pinnacle West
Capital Corporation. Under the original agreement, we have the right to receive
$6.2 million of the sale proceeds, including a note receivable for $4.9 million
to be paid quarterly beginning on January 1, 2004, and ending with a final
payment on October 1, 2004. In April 2004, Arizona Gas Storage, L.L.C., APACS
Holdings, L.L.C. and EPNG agreed to modify the payment schedule related to the
Copper Eagle purchase, and the new payment terms are expected to be finalized
during the third quarter of 2004. As of June 30, 2004, we have received
principal payments totaling $1.3 million and interest payments totaling $45
thousand from EPNG related to the note receivable.

Indemnifications. 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 not made any claims during the six months
ended June 30, 2004 or 2003. However, for the full year of 2003, we made claims
for approximately $5 million of costs incurred during the year ended December
31, 2003, as costs exceeded the established thresholds for 2003.

Wilson Storage Operating Lease Commitment. In connection with our April
2002 purchase of the EPN Holding assets from subsidiaries of El Paso
Corporation, we obtained a long-term operating lease commitment related to the
Wilson natural gas storage facility, which is operated by one of our direct
subsidiaries. From the acquisition date until the second quarter of 2004, El
Paso Corporation guaranteed our direct subsidiary's payment and performance
under this commitment. In the second quarter of 2004, El Paso Corporation was
released from the guarantee and, thus, we now are solely liable for our direct
subsidiary's payment and performance under this operating lease agreement.

19

Capital Contribution Arrangements. 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 up to $6.1 million, of which $3.0 million has been
collected as of June 30, 2004, from ANR Pipeline Company for our Phoenix
gathering system, which went into service in July 2004. We expect to receive the
remaining amount from ANR Pipeline Company in the third quarter of 2004. The
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.

Unit Option Buyout/Option Plans. As previously discussed in Note 6,
Partners' Capital, we will repurchase employee and director options before the
merger and outstanding restricted units will convert to Enterprise restricted
units or vest at the merger date.

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.

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.

20

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. In April 2004, we
elected to voluntarily cooperate with the Commodity Futures Trading Commission
(CFTC) in connection with the CFTC's industry-wide investigation of activities
affecting the price of natural gas in the fall of 2003. Specifically, the CFTC
requested companies to provide information, on behalf of themselves and their
affiliates, relating to storage reports provided to the Energy Information
Administration for the period of October 2003 through December 2003. We are
cooperating fully with the CFTC's investigation and have provided requested
information for the relevant time period regarding our storage operations at our
Petal and Wilson fields.

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. 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 court's calculation of post 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.

21

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 June 30, 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.

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. We expect to make
capital expenditures for environmental matters of approximately $7 million in
the aggregate for the years 2004 through 2008, primarily to comply with clean
air regulations.

As of June 30, 2004 and December 31, 2003, 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 gas meters. We assumed this liability in connection with
our April 2002 acquisition of the EPN Holding assets. As part of the April 2002
EPN Holding asset acquisition, El Paso Corporation has agreed to indemnify us
for all the known and unknown environmental liabilities, excluding the
remediation costs associated with mercury gas meters, related to the assets we
purchased up to the purchase of $752 million. Additionally, 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 $764 million. We will be
indemnified for liabilities discovered during the proceeding three years from
the closing date of these acquisitions. In addition, we have been indemnified by
third parties for remediation costs associated with other assets we have
purchased.

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 at the Shoup plant owned by our subsidiary, 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.

22

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.

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 June 1, 2004. On February 9, 2004, each
transmission provider, including Petal and HIOS, filed with the 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. On July 8, 2004, Petal and HIOS filed
separate notices with the FERC withdrawing their requests. The FERC has not
acted on the requests and they remain pending. However, we believe compliance
with this Final Rule should not place an undue burden 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 have filed briefs on exceptions to this decision. In August 2004, HIOS filed
an offer of settlement to resolve all issues in the rate case with the FERC.
This settlement is the result of negotiations among HIOS and all but one of the
customers participating in the rate case. In addition, the FERC Staff is not a
party to the settlement. Comments on the settlement are due on August 25, 2004,
and reply comments on September 7, 2004. The settlement is subject to the
approval of the FERC.

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. This was primarily associated with an unexplained
increase in our fuel use which was not contemporaneously collected from our
customers. We initially believed 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 2002. We conducted a thorough review
of our operations and were unable to determine the exact cause of the increase
in fuel use. The fuel use has since returned to historical levels. As of June
30, 2004, we have recorded gross fuel differences of approximately $7.5 million,
which we included in our non-current assets on our balance sheet. In the future,
we expect to have an opportunity to file for collection of the fuel differences.
However, at this time we are not able to determine what amount, if any, may be
collectible from our customers. Any amounts we are unable to resolve or collect
from our customers will negatively impact the future results of our natural gas
pipelines and plants segment.

23

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. On July 12, 2004, GulfTerra Texas filed its response including its
recalculations of rates, plan for unbundling gathering and transmission rates,
and its refund plan. The amount of refunds we calculated are immaterial.
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, and the request remains pending.

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 hearing on
this matter, scheduled for June 29, 2004, has been postponed and no new hearing
date has been established. 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 ventures (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.

24

We estimate the entire $11.2 million of unrealized losses included in
accumulated other comprehensive income at June 30, 2004, will be reclassified
from accumulated other comprehensive income as a reduction to earnings over the
next six 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 June 30, 2004 and December 31, 2003, the fair value of these
cash flow hedges was a liability of $7.3 million and $5.8 million, as the market
price at those dates was higher than the hedge price. For the quarter and six
months ended June 30, 2004, we reclassified approximately $2.3 million and $4.0
million of unrealized accumulated loss related to these derivatives from
accumulated other comprehensive income as a decrease in revenue. These
reclassifications are included in our natural gas pipelines and plants segment.
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.

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 June 30, 2004 and December 31, 2003, the fair value of these cash
flow hedges was a liability of $3.9 million and $3.3 million. For the quarter
and six months ended June 30, 2004, we reclassified approximately $2.4 million
and $4.6 million of unrealized accumulated loss related to these derivatives
from accumulated other comprehensive income to earnings. These reclassifications
are included in our natural gas pipelines and plants segment. 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 had
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"). In March 2004, these cash flow hedges expired
and we reclassified a gain of approximately $45 thousand from accumulated other
comprehensive income to earnings. This reclassification is included in our
natural gas pipelines and plants segment. 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 more balanced 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.

25

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 NGL hedging activities is J. Aron and Company, an affiliate
of Goldman Sachs, 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.

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 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 periods ended June 30:

- --------

(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 $73.1 million and $121.9 million for the quarter and six
months ended June 30, 2003 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.

27

A reconciliation of our segment performance cash flows to our net income is
as follows:

12. GUARANTOR FINANCIAL INFORMATION

As of June 30, 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 each of our subsidiaries, excluding our
unrestricted subsidiaries. Non-guarantor subsidiaries for the quarter and six
months ended June 30, 2004, consisted of our unrestricted subsidiaries.
Non-guarantor subsidiaries for the quarter and six months ended June 30, 2003,
consisted of Matagorda Island Area Gathering System, Arizona Gas Storage,
L.L.C., GulfTerra Arizona Gas, L.L.C., Cameron Highway Pipeline GP I, L.L.C.,
Cameron Highway Pipeline II, L.P., Cameron Highway Pipeline III, L.P., and
Cameron Highway Oil Pipeline Company.

28

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.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE QUARTER ENDED JUNE 30, 2004

29

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE QUARTER ENDED JUNE 30, 2003

- ---------------

(1) Operating revenues and cost of natural gas and other products for our
guarantor subsidiaries has been reduced by $73.1 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.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 2004

30

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 2003

- ---------------

(1) Operating revenues and cost of natural gas and other products for our
guarantor subsidiaries has been reduced by $121.9 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.

31

CONDENSED CONSOLIDATING BALANCE SHEETS
JUNE 30, 2004

32

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2003

33

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2004

34

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2003

35

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.

We have experienced substantial growth over the last several years through
a series of large strategic acquisitions including our San Juan gathering and
processing system in New Mexico and our Texas intrastate gas gathering and
transmission system, both of which were purchased from El Paso Corporation in
2002. In the future, we expect to continue our growth strategy from our
significant portfolio of organic development projects located in the Gulf of
Mexico, which are slated to be completed in the second half of 2004 to 2006 time
period. This expansion strategy started with a first generation of offshore
projects initiated by us in the mid to late 1990s. These projects included the
acquisition and construction of oil and natural gas pipelines and hub platforms
situated along the edge of the outer continental shelf (OCS) to serve
discoveries beyond the OCS. Subsequently, we developed a second generation of
projects which consisted of interconnecting GulfTerra-owned and producer-owned
gathering systems to our OCS pipeline headers and hub platforms, giving us a
competitive reach into the prolific areas of development in the deepwater trend.
In recent years, we have moved into a third stage of offshore infrastructure
projects which consist of interconnecting our earlier generation offshore assets
through the construction of deepwater pipeline extensions to newly installed
GulfTerra-owned and producer-owned deepwater hub platforms. These third
generation projects, which are anchored by major discoveries in the deepwater
area, are expected to create a seamless infrastructure which should accelerate
the development of satellite fields and competitively position us for the next
generation of deeper discoveries.

During the second quarter of 2004, we completed the installation of our
Marco Polo oil and natural gas pipelines, and we began receiving first
production on our 50 percent owned Marco Polo TLP in July 2004. Additionally, in
July 2004, we received first production from the Red Hawk field through our
recently completed Phoenix gathering system. Further, during the quarter we
reached agreement to build another pipeline project in the deepwater Gulf of
Mexico to provide oil and natural gas gathering services from the Ticonderoga
and Constitution fields, which are 100 percent owned by Kerr-McGee Oil & Gas
Corporation (Kerr-McGee), a wholly owned affiliate of Kerr-McGee Corporation.
First production from this project is scheduled for the first half of 2006 and
is dedicated to our 50 percent owned Cameron Highway oil pipeline system which
is nearing completion.

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.

36

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; and

- 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.

On June 22, 2004, Enterprise's registration statement on Form S-4 was
declared effective by the SEC. On July 29, 2004, our common and Series C
unitholders approved the adoption of the merger agreement to combine us with a
wholly-owned subsidiary of Enterprise. See Part II, Other Information, Item 4.
Submission of Matters to a Vote of Security Holders, for the results of the
unitholder vote. We expect the completion of the merger to occur in the third
quarter of 2004, although it remains subject to review by the FTC and the
satisfaction of other conditions to close.

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. In March 2004, we recorded a liability and a related
deferred charge of $4.3 million, which was 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
charge 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 and six months ended June 30, 2004,
we amortized $2.2 million and $2.8 million to expense. As of June 30, 2004, the
remaining deferred charge was $1.5 million. 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. During the quarter and six months ended June 30, 2004,
we recognized expenses for legal and audit fees totaling $1.4 million and $1.5
million associated with our pending merger with Enterprise. We expect to incur
additional merger-related costs prior to the actual date of the merger including
incremental legal, audit and advisory fees. 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.

Under the merger agreement with Enterprise, we are obligated to repurchase,
at reasonable prices, before the effective time of the merger, all outstanding
employee and director unit options that have not been exercised or otherwise
canceled. Approximately 1,000,000 common unit options were outstanding at June
30, 2004, held by 28 current and former employees and directors. Since we do not
have the right under our option plan to force our option holders to sell their
options, we were required to negotiate a separate option purchase agreement
individually with each option holder. The governance and compensation committee
of our general partner's board of directors engaged an independent financial
advisor to assist in the determination of the appropriate repurchase prices for
the outstanding options. Subsequent to June 30, 2004, we entered into option
purchase agreements with all the option holders under which we have agreed to
purchase for cash and/or common units, and the option holders have agreed to
sell, any options that remain outstanding on the merger closing date for a
negotiated price. Each option purchase agreement permits the option holder to
exercise any or all of his or her options at any time and from time to time
prior to the merger closing. Based on information provided by the financial
advisor engaged by the governance and compensation committee, we estimate that
the value, in the aggregate, of the outstanding options to be repurchased is
approximately $13 million.

37

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. 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
June 30, 2004 and August 5, 2004, was $38.47 and $37.10 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 June 30, 2004, and is included in partners' capital as a component of common
units capital.

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
June 30, 2004 and December 31, 2003.

38

In July 2004, 10 Series F1 convertible units were converted into 261,437
common units, for which the holder of the convertible units paid us $10 million.
Additionally, our general partner contributed to us $0.1 million in cash in
order to maintain its one percent general partner interest.

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 $0.4 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.

INDEBTEDNESS AND OTHER OBLIGATIONS

In April 2004, we redeemed, at a premium, approximately $39.1 million in
principal amount of our 8 1/2% senior subordinated notes due June 2010. We used
the proceeds from the conversion of our Series F1 convertible units to fund this
redemption. In connection with the redemption of the notes, we recognized
additional expense during the quarter ended June 30, 2004, totaling $4.1 million
resulting from the payment of the redemption premium and the write-off of
unamortized debt issuance costs. We accounted for these costs as an expense in
accordance with the provisions of SFAS No. 145.

In May 2004, we obtained an additional $200 million senior secured term
loan which we initially used to temporarily reduce indebtedness under our $700
million revolving credit facility and subsequently to fund the redemption of our
$175 million aggregate principal amount of 10 3/8% senior subordinated notes due
2009. The new senior secured term loan is payable in semi-=annual installments
of $1.0 million in November and May of each year for the first six installments,
and the remaining balance is due at maturity in October 2007. 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 (described in Item 1, Financial Statements, Note 4)
or LIBOR increased by 2.25%.

In June 2004, we redeemed all of our outstanding $175 million aggregate
principal amount of 10 3/8% senior subordinated notes due 2009. The notes were
redeemed at a redemption price of 105.2% of the principal amount, plus accrued
and unpaid interest up to June 1, 2004. To fund this redemption, we used the
proceeds from our additional $200 million senior secured term loan obtained in
May 2004. This additional amount was initially used to temporarily reduce
indebtedness under our revolving credit facility. In connection with the
redemption of the notes, we recognized additional expense during the quarter
ended June 30, 2004, totaling $12.2 million resulting from the payment of the
redemption premium and the write-off of unamortized debt issuance costs. We
accounted for these costs as an expense in accordance with the provisions of
SFAS No. 145.

See Item 1., Financial Statements, Note 4, for additional discussion of our
debt obligations.

39

The following table presents the timing and amounts of our debt repayment
and other obligations for the years following June 30, 2004, that we believe
could affect our liquidity (in millions):

- ---------------

(1) Interest payable is forecasted based on the notional fixed rate for our
fixed rate securities and based on the June 30, 2004 variable rate for our
variable rate securities.

The close of the merger will constitute a change of control, and thus a
default, under our credit facility. To avoid a default, our credit facility must
be refinanced or amended at or before the closing of the merger. Enterprise has
stated that it currently intends that our credit facility be refinanced before
the closing of the merger and that, if that does not occur, there are reasonable
grounds to believe that our existing credit facility will be amended prior to
the closing of the merger. If the facility is not amended or refinanced prior to
closing, the resulting default would have a material adverse effect on the
combined company. In addition, the closing of the merger 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 closing of the merger. On August 4, 2004, Enterprise announced that one
of its subsidiaries commenced cash tender offers to purchase any and all of our
outstanding senior subordinated and senior notes. In connection with the tender
offers, Enterprise is soliciting consents to proposed amendments that would
eliminate certain restrictive covenants and default provisions contained in the
indentures governing the notes. Enterprise is commencing the tender offers and
consent solicitations in anticipation of completing the merger, and the merger
is a non-waivable condition to the completion of the tender offers and consent
solicitations. We and Enterprise can agree on the date of the merger closing
after the receipt of all necessary approvals. We do not intend to close until
appropriate financing or other arrangements are in place.

40

INDUSTRIAL DEVELOPMENT 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 million in Industrial Development Revenue Bonds to GulfTerra
Field Services, L.L.C., our direct, wholly-owned subsidiary. 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. We have netted the loan amount and the
bond amount of $52 million and the interest payable and interest receivable
amount of $0.6 million on our balance sheet as of June 30, 2004. We have also
netted the interest expense and interest income amount of $0.6 million on our
income statements for the quarter and six months ended June 30, 2004. Our
presentation of the Industrial Development Revenue Bonds is reflected in
accordance with the provisions of FIN No. 39, Offsetting of Amounts Related to
Certain Contracts, and SFAS No. 140, Accounting for Transfers and Services of
Financial Assets and Extinguishments of Liabilities, since we have the ability
and intent to offset these items.

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 cannot make capital
expenditures, without Enterprise's consent, in excess of $5 million individually
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 provide capital
from operating cash flows 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 quarters ended June 30 and March 31, 2004 as presented in
our 2003 Annual Report on Form 10-K, as amended, was $41 million and $76
million; however, our actual expenditures were approximately $38 million and $48
million.

41

The table below depicts our estimate of projects and capital maintenance
expenditures through June 30, 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 entered into definitive agreements.

FORECASTED EXPENDITURES

- ---------------

(1) We do not plan to make any significant capital expenditures for
environmental matters within the next twelve months.

CONSTRUCTION PROJECTS

- ---------------

(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 June 30, 2004) from ANR Pipeline
Company for our Phoenix gathering system, which went into service in July
2004. We expect to receive the remaining $3.1 million from ANR Pipeline
Company in the third quarter of 2004. 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, which went into service in July 2004.

(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 expect to have the cavern in
service during the fourth quarter of 2004. In the second quarter of 2004 , Petal
executed agreements with BP Energy Company for the 1.8 Bcf of firm storage
capacity in the new natural gas cavern. The agreement is for a five-year term
and is anticipated to commence in October 2004. This commitment increases BP's
position at Petal to 3.45 Bcf. We expect to fund the conversion project costs
through internally generated funds and borrowings under our credit facility.

42

CONSTITUTION GATHERING SYSTEM

In July 2004, we announced we had entered into a definitive agreement to
construct, own, and operate oil and natural gas pipelines to provide firm
gathering services from the Constitution field, which is 100 percent owned by
Kerr-McGee. The Constitution field is located in 5,300 feet of water in Green
Canyon Blocks 679 and 680 in the Central Gulf of Mexico. The new 32-mile,
16-inch natural gas pipeline will have a capacity of up to 200 MMcf/d and will
connect to our existing Anaconda Gathering System (the combination of our Marco
Polo natural gas pipeline and our Typhoon natural gas pipeline). The new oil
pipeline will be a 70-mile, 16-inch line with a minimum capacity of 80 MBbls/d
that will connect with the Cameron Highway Oil Pipeline and Poseidon Oil
Pipeline systems at the new Ship Shoal 332B platform. We plan to install the new
pipelines in the summer of 2005, with first production scheduled for the first
half of 2006. Kerr-McGee has dedicated production from its Constitution and
Ticonderoga discoveries, as well as future potential production from several
undeveloped blocks in the area, for gathering on our new oil and natural gas
pipelines. We expect to fund this construction project through internally
generated funds and borrowings under our credit facility.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $136.2 million for the six
months ended June 30, 2004, compared to $134.2 million for the same period in
2003. This increase was primarily attributable to higher operating cash flows
generated by our Texas intrastate pipeline system, NGL pipeline systems, and
Falcon Nest platform. This increase was partially offset by lower distributions
from our unconsolidated affiliate, Poseidon, as Poseidon began withholding
distributions to fund its capital expenditures related to its Front Runner oil
pipeline.

CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities was approximately $103.9 million for
the six months ended June 30, 2004. Our investing activities included capital
expenditures of $86.1 million primarily related to our Marco Polo pipelines,
Phoenix gathering system and the San Juan optimization project, as well as
maintenance expenditures related to our Chaco plant, San Juan gathering system,
Texas Intrastate system and our NGL pipeline systems. Our investing activities
also included additions to investments in unconsolidated affiliates of $17.9
million, of which $14.2 million related to additional equity contributions we
made to Deepwater Gateway for the construction of the Marco Polo TLP and $3.7
million related to the capitalization of interest associated with our equity
investments in Deepwater Gateway and Cameron Highway.

CASH USED IN FINANCING ACTIVITIES

Net cash used in financing activities was approximately $29.4 million for
the six months ended June 30, 2004. During 2004, cash used in our financing
activities included repayments on our revolving credit facility, repayments of
our long-term debt and 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, the proceeds received from our additional senior secured term loan
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.

43

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 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.

A reconciliation of our segment performance cash flows to our net income is
as follows:

44

NATURAL GAS PIPELINES AND PLANTS

- ---------------

(1) Earnings from unconsolidated affiliates for the quarters ended June 30, 2004
and 2003, were $584 thousand and $626 thousand. Earnings from unconsolidated
affiliates for the six months ended June 30, 2004 and 2003, were $1,118
thousand and $1,255 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 and plants 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 attributable to our ownership percentage.
Included in our cost of natural gas and other products is the payment to the
producers for the NGL 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.

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. This was primarily associated with an unexplained
increase in our fuel use which was not contemporaneously collected from our
customers. We initially believed 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 2002. We conducted a thorough review
of our operations and were unable to determine the exact cause of the increase
in fuel use. The fuel use has since returned to historical levels. As of June
30, 2004, we have recorded gross fuel differences of approximately $7.5 million,
which we included in other non-current assets on our balance sheet. In the
future, we expect to have an opportunity to file for collection of the fuel
differences. However, at this time we are not able to determine what amount, if
any, may be collectible from our customers. Any amounts we are unable to resolve
or collect from our customers will negatively impact the future results of our
natural gas pipelines and plants segment.

45

In July 2004, we completed a number of our natural gas pipeline
construction projects including the Marco Polo natural gas pipeline and the
Phoenix gathering system (described below). As a result of these natural gas
pipeline systems being placed into service, we now own interests in natural gas
pipeline systems with a combined maximum design capacity (net to our interest)
of over 11.8 Bcf/d of natural gas, up from 10.9 Bcf/d. Additionally, we expect
an increase in transportation revenues in the second half of 2004 derived from
producer transportation on these systems.

Marco Polo Natural Gas Pipeline

In July 2004, we completed construction on our 75-mile, 18-inch to 20-inch
natural gas pipeline that supports the Marco Polo TLP. The Marco Polo natural
gas pipeline has a capacity of 400 MMcf/d and interconnects with our Typhoon
natural gas pipeline in Green Canyon Block 236.

Phoenix Gathering System

In July 2004, we completed construction on our 78-mile, 18-inch natural gas
gathering system. The Phoenix gathering system has a capacity of 450 MMcf/d and
interconnects with the ANR Patterson Offshore pipeline system at Vermillion
Block 397.

Second Quarter Ended June 30, 2004 Compared With Second Quarter Ended June 30,
2003

Natural gas pipelines and plants margin for the quarter ended June 30,
2004, was $9.7 million higher than in the same period in 2003. This increase was
primarily due to a $9.8 million increase in margin for our Texas intrastate
pipeline system. During the second quarter of 2003, the Texas intrastate
pipeline system experienced an unexplained increase in fuel used on the system,
which resulted in a $3.0 million reduction in margin. Additionally, at June 30,
2003, we had an imbalance payable position of 6.3 Bcf that resulted in a $3.9
million revaluation impact, which also decreased margin. During the second
quarter of 2004, margin on the Texas intrastate system was not impacted by those
same events as our fuel use on the system had returned to historical levels and
our imbalance position at June 30, 2004, had decreased significantly to a
payable position of 0.4 Bcf. Additionally, we had a $2.3 million increase in
margin at our Texas intrastate pipeline system related to an increase in base
business over the same period in 2003. Margin also increased by $2.3 million at
our Chaco processing plant due to higher NGL prices as compared to the same
period in 2003. Partially offsetting these increases was a $1.6 million decrease
in margin at our Indian Basin gas plant attributable to lower volumes due to
plant maintenance in the second quarter of 2004.

Operating expenses excluding depreciation, depletion and amortization for
the quarter ended June 30, 2004, were $3.9 million higher than the same period
in 2003 primarily due to timing of expenditures associated with normal recurring
operating expenses and an increase in allocated administrative costs, including
merger-related costs and directors and officers liability insurance. These
increases were partially offset by a $2.0 million increase in our allowance for
doubtful accounts recorded in 2003.

Six Months Ended June 30, 2004 Compared With Six Months Ended June 30, 2003

Natural gas pipelines and plants margin for the six months ended June 30,
2004, was $19.8 million higher than in the same period in 2003. This increase
was primarily due to a $21.5 million increase in margin for our Texas intrastate
pipeline system. During the six months ended June 30, 2003, the Texas intrastate
pipeline system experienced an unexplained increase in fuel used on the system,
which resulted in a $7.2 million reduction in margin. Additionally, at June 30,
2003, we had an imbalance payable position of 6.3 Bcf that resulted in a $9.4
million revaluation impact, which also decreased margin. During the six months
ended June 30, 2004, margin on the Texas intrastate system was not impacted by
those same events as our fuel use on the system had returned to historical
levels and our imbalance position at June 30, 2004, had decreased significantly
to a payable position of 0.4 Bcf. Additionally, we had a $4.4 million increase
in margin at our Texas intrastate pipeline system related to an increase in base
business over the same period in 2003. Margin also increased by $3.5 million due
to an increase in volumes during 2004 on our San Juan gathering system
46

and $2.4 million due to additional volumes on our Falcon Nest pipeline. San Juan
gathering volumes were higher in 2004 as compared to 2003 due to a turbine
outage at the Blanco plant in 2003 which resulted in volumes being shut in on
the gathering system. Volumes are up on the Falcon Nest pipeline reflecting a
full six months of operation as compared to 2003. Partially offsetting these
increases was a $3.0 million decrease in margin at our Indian Basin gas plant
attributable to lower volumes due to plant maintenance in the second quarter of
2004 and colder temperatures in the first quarter of 2004. These increases were
also offset by an additional $3.0 million of increased fuel costs at our Permian
Basin gathering systems over the same period in 2003.

Operating expenses excluding depreciation, depletion and amortization for
the quarter ended June 30, 2004, were $9.8 million higher than the same period
in 2003 primarily due to timing of expenditures associated with normal recurring
operating expenses and an increase in allocated administrative costs, including
merger-related costs and directors and officers liability insurance. These
increases were partially offset by a $2.0 million increase in our allowance for
doubtful accounts recorded in 2003.

OIL AND NGL LOGISTICS

- ----------

(1) Earnings from unconsolidated affiliates for the quarters ended June 30, 2004
and 2003, were $1,379 thousand and $2,361 thousand. Earnings from
unconsolidated affiliates for the six months ended June 30, 2004 and 2003,
were $3,169 thousand and $5,048 thousand.

(2) Represents 100 percent of Poseidon volumes.

47

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 NGL and by volumes.
Both oil and NGL 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 and six months ended
June 30, 2003, we reduced by $73.1 million and $121.9 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,
performance cash flows or partners' capital.

In July 2004, we completed our construction of the Marco Polo oil pipeline.
We now own interests in four offshore oil pipeline systems with a combined
capacity of approximately 755 MBbls/d, up from 635 MBbls/d, of oil with the
addition of pumps and the use of friction reducers.

Marco Polo Oil Pipeline

The Marco Polo oil pipeline is a 36-mile, 14-inch oil pipeline that
supports the Marco Polo TLP. The Marco Polo oil pipeline has a capacity of 120
MBbls/d and interconnects with our Allegheny oil pipeline in Green Canyon Block
164. We expect an increase in transportation revenues in the second half of 2004
derived from producer transportation on this system.

Front Runner Oil Pipeline

In July 2004, Poseidon, our 36 percent owned joint venture, completed
construction of its 36-mile, 14-inch Front Runner oil pipeline and first
production is anticipated in the fourth quarter of 2004. The new oil pipeline
has a capacity of 65 MBbls/d and connects the Front Runner platform with
Poseidon's existing system at Ship Shoal Block 332. In October 2003, Poseidon
began withholding distributions to fund its capital expenditures related to its
Front Runner project. Since Poseidon has completed its construction of the Front
Runner oil pipeline, we expect to start receiving distributions again in late
2004 or early 2005.

Cameron Highway Oil Pipeline

The Cameron Highway oil pipeline will be a 390-mile crude oil pipeline
system with a capacity of approximately 500 MBbls/d. In July 2003, we sold a 50
percent interest in our Cameron Highway oil pipeline to Valero Energy
Corporation (Valero) for $86 million, forming a joint venture with Valero.
Valero paid us approximately $70 million at closing, including $51 million
representing 50 percent of the capital investment expended through that date for
the pipeline project. Valero will pay us an additional $5 million once the
system is completed, which is expected in the fourth quarter of 2004. We expect
to reflect this amount as a gain from the sale of long-lived assets in the
fourth quarter of 2004. In addition, we will receive another $11 million by the
end of 2006. We expect to reflect this amount as a gain from the sale of
long-lived assets in the period it is earned. We do not expect to receive
distributions from Cameron Highway until 2006 due to the debt service covenants
on Cameron Highway's project finance facility.
48

Additionally, in July 2004, we announced that Cameron Highway had executed
an agreement with Kerr-McGee for the dedication and movement of crude oil
production from the Constitution and Ticonderoga fields, along with other future
production from several undeveloped blocks in the south Green Canyon area of the
deepwater trend of the Gulf of Mexico. Under the terms of the agreement,
production from Kerr-McGee's interest in Constitution, Ticonderoga and
surrounding undeveloped blocks is dedicated to the Cameron Highway oil pipeline
system for the life of the reserves. Cameron Highway expects volumes from these
fields in the first half of 2006. Further, we will construct and own a 70-mile,
16-inch oil pipeline which will connect the Constitution and Ticonderoga fields
with the Cameron Highway oil pipeline at the new Ship Shoal 332B platform. We
plan to install the new oil pipeline in the summer of 2005, with first
production scheduled for the first half of 2006.

Second Quarter Ended June 30, 2004 Compared With Second Quarter Ended June 30,
2003

For the quarter ended June 30, 2004, margin was $3.6 million higher than
the same period in 2003. Margin attributable to our NGL pipeline systems was up
$2.8 million due to an increase in volumes as our NGL pipeline had been down for
maintenance through the third quarter of 2003. In addition, margin from our NGL
fractionation plants increased $1.0 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 June 30, 2004, were $0.7 million higher than the same period
in 2003 primarily due to an increase in allocated administrative costs,
including 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 June 30, 2004, declined $2.5 million.
As discussed above, Poseidon was withholding distributions to fund its capital
expenditures related to its Front Runner project. Poseidon completed its Front
Runner project in July 2004 and we expect to start receiving distributions in
late 2004 or early 2005.

Six Months Ended June 30, 2004 Compared With Six Months Ended June 30, 2003

For the six months ended June 30, 2004, margin was $5.9 million higher than
the same period in 2003. Margin attributable to our NGL pipeline systems was up
$4.2 million due to an increase in volumes as our NGL pipeline had been down for
maintenance through the third quarter of 2003. In addition, margin from our NGL
fractionation plants increased $1.8 million due to higher volumes resulting from
improved processing economics at the plants in 2004.

Operating expenses excluding depreciation, depletion and amortization for
the six months ended June 30, 2004, were $3.1 million higher than the same
period in 2003. This increase was primarily due to timing of expenditures
associated with normal recurring operating expenses and an increase in allocated
administrative costs, including merger-related costs and directors and officers
liability insurance.

Other income and cash distributions from unconsolidated affiliates in
excess of earnings for the six months ended June 30, 2004, declined $6.5
million. As discussed above, Poseidon was withholding distributions to fund its
capital expenditures related to its Front Runner project. Poseidon completed its
Front Runner project in July 2004 and we expect to start receiving distributions
in late 2004 or early 2005.

49

NATURAL GAS STORAGE

- ----------

(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. 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) provides a more
accurate and meaningful basis for analyzing operating results for this segment.

Petal Conversion Project

In the second quarter of 2004, Petal executed agreements with BP Energy
Company for the 1.8 Bcf of firm storage capacity in Petal's new natural gas
storage cavern. The agreements will commence in October 2004, and we expect an
increase in storage revenues in the fourth quarter of 2004 derived from the firm
storage at Petal.

Second Quarter Ended June 30, 2004 Compared With Second Quarter Ended June 30,
2003

For the quarter ended June 30, 2004, margin was $0.4 million higher than
the same period in 2003 primarily due to an increase in interruptible storage
services at our leased Wilson storage facility.

Operating expenses excluding depreciation, depletion and amortization for
the quarter ended June 30, 2004, were $0.8 million higher than the same period
in 2003 primarily due to an increase in allocated administrative costs,
including merger-related costs and directors and officers liability insurance.

50

Six Months Ended June 30, 2004 Compared With Six Months Ended June 30, 2003

For the six months ended June 30, 2004, margin was $2.9 million higher than
the same period in 2003, of which $1.5 million was due to an increase in
interruptible storage services at our leased Wilson storage facility. In
addition, there was a $1.6 million increase in margin at our Hattiesburg gas
storage facility attributable to lower revaluation expense of our natural gas
imbalances due to a lower imbalance position in 2004.

Operating expenses excluding depreciation, depletion and amortization for
the six months ended June 30, 2004, were $1.2 million higher than the same
period in 2003 primarily due to an increase in allocated administrative costs,
including merger-related costs and directors and officers liability insurance.

PLATFORM SERVICES

- ----------

(1) Earnings from unconsolidated affiliates for the quarter and six months ended
June 30, 2004, were $1,295 thousand and $1,209 thousand.

(2) 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.

51

Marco Polo TLP

The Marco Polo TLP was installed in the first quarter of 2004 and commenced
operations in July 2004. Deepwater Gateway L.L.C., the owner of the Marco Polo
TLP, began receiving monthly demand payments of $2.1 million in April 2004 and
volumetric payments started in July 2004. Additionally, in July 2004, Deepwater
Gateway converted its project finance loan into a term loan with payments on the
term loan beginning September 30, 2004. We expect to receive distributions in
2005 from Deepwater Gateway subject to term loan covenants.

In March 2004, Deepwater Gateway 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 47.5 percent working
interest in the K2 Field production on the Marco Polo TLP. Anadarko's 52.5
percent interest in the K2 Field was previously dedicated to the Marco Polo TLP.
Also, production from Anadarko's 100 percent interest in the K2 North Field in
Green Canyon Block 518 will be processed on the Marco Polo TLP. Deepwater
Gateway expects to receive volumes from these fields in the first half of 2005.

Second Quarter Ended June 30, 2004 Compared With Second Quarter Ended June 30,
2003

For the quarter ended June 30, 2004, revenues were slightly higher than in
the same period in 2003. The increase is primarily due to increased volumes from
our Falcon Nest fixed leg platform resulting from new wells coming on line in
the first quarter of 2004.

Operating expenses excluding depreciation, depletion and amortization for
the quarter ended June 30, 2004, were $0.5 million higher than the same period
in 2003 primarily due to an increase in allocated administrative costs,
including merger-related costs and directors and officers liability insurance.

Six Months Ended June 30, 2004 Compared With Six Months Ended June 30, 2003

For the six months ended June 30, 2004, revenues were $2.2 million higher
than in the same period in 2003. An increase in volumes from new wells in the
first quarter of 2004 resulted in higher margins of $4.1 million at our Falcon
Nest Platform. Partially offsetting this increase were lower revenues of $1.9
million from East Cameron 373 resulting from lower demand fees.

Operating expenses excluding depreciation, depletion and amortization for
the six months ended June 30, 2004, were $0.5 million higher than the same
period in 2003 primarily due to an increase in allocated administrative costs,
including merger-related costs and directors and officers liability insurance.

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 for the six months ended June
30, 2004 and for the quarter and six months ended June 30, 2003, are the
quarterly payments we received from El Paso Corporation in connection with the
sale of some of our Gulf of Mexico assets in January 2001. The sale of these
assets occurred as a result of a FTC order related to El Paso Corporation's
merger with The Coastal Corporation. 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.
52

Second Quarter Ended June 30, 2004 Compared With Second Quarter Ended June 30,
2003

Performance cash flows related to other, non-segment results for the
quarter ended June 30, 2004, were $0.3 million higher than the same period in
2003 primarily due to a decrease in operating expenses in 2004 of $2.8 million
associated with the allocation of costs to our business segments. The decrease
in operating expenses was offset by the discontinuation of the quarterly
payments we received from El Paso Corporation in connection with the sale of
some of our Gulf of Mexico assets in January 2001. We received the final payment
of $2.0 million in the first quarter of 2004.

Six Months Ended June 30, 2004 Compared With Six Months Ended June 30, 2003

Performance cash flows related to other non-segment results for the six
months ended June 30, 2004, were $0.4 million higher than the same period in
2003 primarily due to a decrease in operating expenses in 2004 of $3.8 million
associated with the allocation of costs to our business segments. The decrease
in operating expenses was offset by the discontinuation of the quarterly
payments we received from El Paso Corporation in connection with the sale of
some of our Gulf of Mexico assets in January 2001. We received the final payment
of $2.0 million in the first quarter of 2004.

DEPRECIATION, DEPLETION, AND AMORTIZATION

Depreciation, depletion and amortization for the quarter ended June 30,
2004 was $1.2 million higher than the same period in 2003 primarily due to an
increase in depreciation expense of $1.2 million related to assets placed in
service during 2003, including our communication assets placed in service in
October 2003 and the Viosca Knoll pipeline extension placed in service in
December 2003. Additionally, we had an increase in depreciation expense of $0.7
million associated with an increase in the costs assigned to the San Juan assets
we purchased in November 2002 as a result of the final purchase price
allocation. This increase in depreciation expense was partially offset by a
decrease in depreciation expense of $0.6 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.

Depreciation, depletion and amortization for the six months ended June 30,
2004 was $3.8 million higher than the same period in 2003 primarily due to an
increase in depreciation expense of $2.3 million from assets placed in service
during 2003, including our communication assets placed in service in October
2003 and the Viosca Knoll pipeline extension placed in service in December 2003.
Additionally, we had an increase in depreciation expense of $0.3 million
resulting from additional capital expenditures on our Falcon Nest pipeline and
platform, $1.5 million associated with an increase in the costs assigned to the
San Juan assets we purchased in November 2002 as a result of the final purchase
price allocation and increased depletion of $0.8 million resulting from the
true-up of reserves based on revised reserve estimates. This increase in
depreciation expense was partially offset by a decrease in depreciation expense
of $1.1 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.

INTEREST AND DEBT EXPENSE

Interest and debt expense, net of capitalized interest, for the quarter
ended June 30, 2004, was approximately $5.1 million lower than the same period
in 2003. This decrease is primarily due to the redemption of a portion of our
senior subordinated notes in April 2004 and December 2003 and the full
redemption of our $175 million 10 3/8% senior subordinated notes due 2009 in
June 2004. Additionally, interest and debt expense decreased as a result of
lower weighted average interest rates on our revolving credit facility and
senior secured term loan and the repayment of our GulfTerra Holding term loan
during the third quarter of 2003. Partially offsetting these decreases were
increased interest expenses associated with the additional senior secured term
loan we obtained in May 2004, the senior notes we issued in July 2003 and the
increased weighted average debt outstanding on our revolving credit facility and
our already-existing senior secured term loan.

53

Interest and debt expense, net of capitalized interest, for the six months
ended June 30, 2004, was approximately $11.6 million lower than the same period
in 2003. This decrease is primarily due to the redemption of a portion of our
senior subordinated notes in April 2004 and December 2003 and the full
redemption of our $175 million 10 3/8% senior subordinated notes due 2009 in
June 2004. Additionally, interest and debt expense decreased as a result of
lower weighted average interest rates on our revolving credit facility and
senior secured term loan, decreased weighted average debt outstanding on our
revolving credit facility, the repayment of our GulfTerra Holding term loan
during the third quarter of 2003 and the repayment of our senior secured
acquisition term loan in March 2003. Partially offsetting these decreases were
increased interest expenses associated with the additional senior secured term
loan we obtained in May 2004, the senior notes we issued in July 2003 and the
increased weighted average debt outstanding on our already-existing senior
secured term loan.

Capitalized interest for the quarter and six months ended June 30, 2004,
was $3.9 million and $7.6 million, representing increases of $1.3 million and
$3.1 million over the comparable prior periods. The increase is the result of
higher expenditures related to our construction projects, primarily the Marco
Polo natural gas and oil pipelines, the Phoenix gathering system and the Cameron
Highway oil pipeline system. This increase was partially offset by reduced
expenditures on construction projects placed into service in 2003, primarily the
Viosca Knoll pipeline extension and the Falcon Nest natural gas pipeline and
platform, and on the Marco Polo TLP which was installed in the first quarter of
2004.

LOSS DUE TO EARLY REDEMPTIONS OF DEBT

In June 2004, we redeemed all of our outstanding $175 million aggregate
principal amount of 10 3/8% senior subordinated notes due 2009 and we recognized
a loss of $12.2 million resulting from the payment of the redemption premium and
the write-off of unamortized debt issuance costs.

In April 2004, we redeemed approximately $39.1 million in principal amount
of our 8 1/2% senior subordinated notes due June 2010 and we recognized a loss
of $4.1 million resulting from the payment of the redemption premium and the
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 six months ended June
30, 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.

54

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.

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.

55

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 $11.2 million of unrealized losses included in
accumulated other comprehensive income at June 30, 2004, will be reclassified
from accumulated other comprehensive income as a reduction to earnings over the
next six 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 June 30, 2004 and December 31, 2003, the fair value of these
cash flow hedges was a liability of $7.3 million and $5.8 million, as the market
price at those dates was higher than the hedge price. For the quarter and six
months ended June 30, 2004, we reclassified approximately $2.3 million and $4.0
million of unrealized accumulated loss related to these derivatives from
accumulated other comprehensive income as a decrease in revenue. These
reclassifications are included in our natural gas pipelines and plants segment.
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.

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 June 30, 2004 and December 31, 2003, the
fair value of these cash flow hedges was a liability of $3.9 million and $3.3
million. For the quarter and six months ended June 30, 2004, we reclassified
approximately $2.4 million and $4.6 million of unrealized accumulated loss
related to these derivatives from accumulated other comprehensive income to
earnings. These reclassifications are included in our natural gas pipelines and
plants segment. 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 had
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. In March 2004, these cash flow hedges
expired and we reclassified a gain of approximately $45 thousand from
accumulated other comprehensive income to earnings. This reclassification is
included in our natural gas pipelines and plants segment. 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.

56

In July 2003, to achieve a more balanced 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.

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 "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 material
weaknesses.
57

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 and the Audit and Conflicts Committee of our
general partner's board of directors. 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 material weaknesses in internal control
as defined by the Public Company Accounting 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.

58

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, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On July 29, 2004, we held a special meeting of our common and Series C
unitholders to vote upon the adoption and approval of the Merger Agreement,
dated as of December 15, 2003, by and among Enterprise Products Partners, L.P.,
Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra
Energy Partners, L.P. and GulfTerra Energy Company, L.L.C., to combine our
business with that of Enterprise by merging us into a wholly-owned subsidiary of
Enterprise. The merger agreement was approved by our common and Series C
unitholders with the following numbers of votes cast: 37,353,838 votes were cast
in favor of approval, 597,941 votes were cast against approval and there were
180,352 abstentions.

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.

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 April 20, 2004 to announce that
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 had 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).

We filed a Current Report on Form 8-K dated June 2, 2004 to announce our
redemption of the entire $175 million outstanding aggregate principal amount of
our 10 3/8% senior subordinated notes due 2009 and to announce we had obtained a
$200 million senior secured term loan in addition to our existing $300 million
senior secured term loan.

We filed a Current Report on Form 8-K dated June 25, 2004 to announce our
subsidiary, Petal Gas Storage, L.L.C. will hold a non-binding open season from
Wednesday July 7, 2004, through Thursday, July 22, 2004, to determine market
interest for up to 5.0 Bcf of firm natural gas capacity at its Petal Gas Storage
facility, and up to 500,000 MMBtu/d of firm transportation on the Petal
pipeline, all available in the third quarter of 2007. The storage and
transportation capacities became available when the Letter of Intent between
Petal and Southern Natural Gas Company expired in June 2004.

61

We filed a Current Report on Form 8-K dated July 8, 2004 to announce that
we had reached a definitive agreement to construct, own, and operate oil and gas
export pipelines to provide firm gathering services from the Constitution field,
which is 100 percent owned by Kerr-McGee.

We filed a Current Report on Form 8-K dated July 16, 2004 to announce that
Cameron Highway Oil Pipeline Company, a venture jointly owned by us and Valero,
executed an agreement with Kerr-McGee for the dedication and movement of crude
oil production from the Constitution and Ticonderoga fields, along with other
future potential production from several undeveloped blocks in the south Green
Canyon area of the deepwater trend of the Gulf of Mexico.

We filed a Current Report on Form 8-K dated July 20, 2004 to announce that
our jointly owned Marco Polo Tension Leg Platform commenced processing initial
oil and gas production from Anadarko Petroleum Corporation's Marco Polo field in
Green Canyon Block 608.

We filed a Current Report on Form 8-K dated July 21, 2004 to announce that
we commenced operations of the Phoenix gas pipeline and recently received
initial production from the Red Hawk field located in the Garden Banks area of
the central deepwater trend in the Gulf of Mexico.

We filed a Current Report on Form 8-K dated July 30, 2004 to announce that
our unitholders approved the proposed merger between us and Enterprise in our
unitholder meeting held July 29, 2004.

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.

62

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: August 9, 2004 By: /s/ WILLIAM G. MANIAS
------------------------------------
William G. Manias
Vice President and Chief Financial
Officer
(Principal Financial Officer)

Date: August 9, 2004 By: /s/ KATHY A. WELCH
------------------------------------
Kathy A. Welch
Vice President and Controller
(Principal Accounting Officer)

63

INDEX TO EXHIBITS