GULFTERRA ENERGY PARTNERS L P - 10-Q Quarterly Report

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

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FORM 10-Q
(MARK ONE)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

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

Former telephone number: (832) 676-6152

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 49,794,421 common units outstanding as of August 7,
2003.

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

GULFTERRA ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)

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 INCOME
(IN THOUSANDS)
(UNAUDITED)

COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

See accompanying notes.

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GULFTERRA ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

In May 2003, we changed our name to GulfTerra Energy Partners, L.P. from El
Paso Energy Partners, L.P. and reorganized our general partner. Our one percent
general partner interest is now owned by GulfTerra Energy Company, L.L.C.
replacing El Paso Energy Partners Company as the general partner. In connection
with our name change, we have also changed the names of several subsidiaries
including, but not limited to the following, as listed in the table below.

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 2002 Annual Report on
Form 10-K, which includes a summary of our significant accounting policies and
other disclosures. The financial statements as of June 30, 2003, and for the
quarters and six months ended June 30, 2003 and 2002, are unaudited. We derived
the balance sheet as of December 31, 2002, from the audited balance sheet filed
in our 2002 Annual Report on Form 10-K. 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. We have
also reflected the results of operations from our Prince assets disposition as
discontinued operations in the quarter and six months ended June 30, 2002.

Our accounting policies are consistent with those discussed in our 2002
Annual Report on Form 10-K, except as discussed below.

Allowance for Doubtful Accounts

We have established an allowance for losses on accounts that we believe are
uncollectible. Collectibility is reviewed regularly and the allowance is
adjusted as necessary, primarily under the specific identification method.
During the quarter ended June 30, 2003, we increased our allowance by $2.0
million. As of June 30, 2003 and December 31, 2002, our allowance was $4.5
million and $2.5 million.
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As generally used in the energy industry and in this document, the following
terms have the following meanings:

/d = per day Mcf = thousand cubic feet
Bbl = barrel MDth = thousand dekatherms
MBbls = thousand barrels MMcf = million cubic feet
Bcf = billion cubic feet MMBbls = million barrels
When we refer to cubic feet measurements, all measurements are at 14.73 pounds per square inch.

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Accounting for Asset Retirement Obligations

On January 1, 2003, we adopted Statement of Financial Accounting Standards
(SFAS) No. 143, Accounting for Asset Retirement Obligations. The provisions of
this statement relate primarily to our obligations to plug abandoned offshore
wells in our Garden Banks Blocks 72 and 117, Viosca Knoll Block 817, and West
Delta Block 35.

Upon our adoption of SFAS No. 143, we recorded a $7.4 million net increase
to property, plant, and equipment representing non-current retirement assets, a
$5.7 million increase to noncurrent liabilities, representing retirement
obligations, and a $1.7 million increase to income as a cumulative effect of
accounting change. The retirement assets are depreciated over the remaining
useful life of the long-term asset with which the retirement liability is
associated. An ongoing expense is recognized for changes in the value of the
retirement liability as a result of the passage of time, which we record as
depreciation, depletion and amortization expense in our income statement.

Other than our obligations to plug and abandon wells, we cannot estimate
the costs to retire or remove assets used in our business because we believe the
assets do not have definite lives or we do not have the legal obligation to
abandon or dismantle the assets. We believe that the life of our assets or the
underlying reserves associated with our assets cannot be estimated. Therefore,
aside from the liability associated with the plug and abandonment of offshore
wells, we have not recorded liabilities relating to any of our other assets.

The pro forma income from continuing operations and amounts per unit for
the quarter and six months ended June 30, 2003 and 2002, assuming asset
retirement obligations as provided for in SFAS No. 143 were recorded prior to
the earliest period presented, are shown below:

The pro forma amount of our asset retirement obligations at June 30, 2003
and 2002 and at December 31, 2002, assuming asset retirement obligations as
provided for in SFAS No. 143 were recorded prior to the earliest period
presented are shown below:

Reporting Gains and Losses from the Early Extinguishment of Debt

In January 2003, we adopted SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
Accordingly, we now evaluate the nature of any debt extinguishments to determine
whether to report any gain or loss resulting from the early extinguishment of
debt as an extraordinary item or as income from continuing operations.

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Accounting for Costs Associated with Exit or Disposal Activities

In January 2003, we adopted SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement impacts any exit or disposal
activities that we initiate after January 1, 2003 and we now recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Our adoption of this pronouncement
did not have an effect on our financial position or results of operations.

Accounting for Guarantees

In accordance with the provisions of Financial Accounting Standards Board
(FASB) Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, we record a liability at fair value, or otherwise disclose, certain
guarantees issued after December 31, 2002, that contractually require us to make
payments to a guaranteed party based on the occurrence of certain events. We
have not entered into any material guarantees that would require recognition
under FIN No. 45.

Consolidation of Variable Interest Entities

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51. 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. This standard requires that companies consolidate a VIE if it is
allocated a majority of the entity's losses and/or returns, including fees paid
by the entity. We have not created nor have we obtained an interest in any VIEs
since January 31, 2003, and therefore, our adoption of the initial provisions of
this standard did not have an effect on our financial position or results of
operations. Further, we have completed an assessment of our interests existing
prior to February 1, 2003, and have determined that our adoption of the
additional provisions of this standard will not have an effect on our financial
position or results of operations.

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 former employees of our general partner and our current
board of directors under our Omnibus Plan and Director Plan. For the quarters
and six months ending June 30, 2003 and 2002, 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 SFAS No. 123 to account for all of our
other stock-based compensation programs.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation Transition and Disclosure. This statement amends SFAS No. 123, to
provide alternative methods of transition for a voluntary change to the fair
value method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements about the
methods of accounting for stock-based employee compensation for former employees
of our general partner and our board of directors, and the effect of the method
used on reported results. This statement is effective for the fiscal years
ending after December 15, 2002. We have decided that we will continue to use APB
No. 25 to value our stock-based compensation issued to our former employees and
our board of directors and will include data providing the pro forma income
impacts of using the fair value method as required by SFAS No. 148. We will
continue to use the provisions of SFAS No. 123 to account for all of our other
stock based compensation programs.

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If compensation expense related to these plans had been determined by
applying the fair value method in SFAS No. 123, Accounting for Stock-Based
Compensation, 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 SFAS No. 123 in this pro forma disclosure may not
be indicative of pro forma future amounts.

2. ACQUISITION

During the six months ended June 30, 2003, the total purchase price and net
assets acquired for the April 2002 EPN Holding asset acquisition increased $17.5
million due to post-closing purchase price adjustments related primarily to
natural gas imbalances assumed in the transaction. The following table
summarizes our allocation of the fair values of the assets acquired and
liabilities assumed. Our allocation among the assets acquired is based on the
results of an independent third-party appraisal.

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3. 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, 2003:

In July 2003 we declared a cash distribution of $0.70 per common unit and
Series C unit, $42.5 million in aggregate, for the quarter ended June 30, 2003,
which we will pay on August 15, 2003, to holders of record as of July 31, 2003.
Also in August 2003, we will pay our general partner $18.0 million related to
its general partner interest. At the current distribution rates, our general
partner receives approximately 29.8 percent of the total cash distributions for
its role as our general partner.

Public offering of common units

In June 2003, we issued 1,150,000 common units at the public offering price
of $36.50 per unit and in April 2003, we issued 3,450,000 common units at the
public offering price of $31.35 per unit. We used the net cash proceeds of
approximately $40.3 million and $103.1 million to temporarily reduce
indebtedness outstanding under our $600 million revolving credit facility and
pay fees and expenses associated with these offerings.

In May 2003, we issued 1,118,881 common units and 80 Series F convertible
units in a registered offering to an institutional investor for approximately
$38.3 million net of offering costs. Our Series F convertible units are not
listed on any securities exchange or market. Each Series F convertible unit is
comprised of two separate detachable units -- a Series F1 convertible unit and a
Series F2 convertible unit -- that have identical terms except for vesting and
termination dates and the number of underlying common units into which they may
be converted. The Series F1 units are convertible into up to $80 million of
common units anytime after August 12, 2003, and until March 29, 2004 (subject to
defined extension rights). The Series F2 units are convertible into up to $40
million of common units provided at least $40 million of Series F1 convertible
units are converted prior to their termination. The Series F2 units terminate on
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 of the prevailing price (as defined below), if the prevailing price is
equal to or greater than $35.75 or 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 days of the 60 day period included in (i). If
they had been eligible for conversion, the price at which the Series F
convertible units could have been converted to common units, based on the
previous 60 business days at June 30, 2003 and August 7, 2003, was $29.67 and
$36.15. The Series F convertible units may be converted into a maximum of
8,329,679 common units and are not entitled to any distributions, nor do they
have any voting rights, prior to conversion. The value associated with the
Series F convertible units is included in partners' capital as a component of
common units.

The Series F convertible units have a feature which allows us to establish
a minimum conversion unit price. Should the actual conversion unit price be
below the minimum conversion unit price, we would be required to settle the
conversion in cash in lieu of issuing common units. Currently, no minimum
conversion unit price has been established; however, if a minimum conversion
unit price is established, we may have to

9

change our accounting treatment for the Series F convertible units to account
for them as a derivative under the provisions of SFAS No. 133 and record an
asset or liability for the fair value of the Series F convertible units, and the
changes in fair value would impact our earnings.

In connection with these offerings, our general partner, in lieu of a cash
contribution, redeemed approximately $1.8 million of our Series B preference
units in order to maintain its one percent general partner interest, and these
preference units were subsequently retired.

Other

Under the 1998 Omnibus Compensation Plan (Omnibus Plan), we granted, during
the quarter ended June 30, 2003, 17,500 unit options, 15,000 time-vested
restricted units and 15,000 performance-based restricted units to employees of
El Paso Field Services. Additionally, 5,226 restricted units and 10,500 unit
options were granted during the quarter ended June 30, 2003, to non-employee
directors of our Board of Directors under the 1998 Unit Option Plan for
Non-Employee Directors. We have accounted for the unit options and restricted
units issued under the Omnibus Plan and the restricted units issued to
non-employee directors of our Board of Directors in accordance with SFAS No.
123. Under SFAS No. 123, the fair value of these issuances is reflected as
deferred compensation. Deferred compensation is amortized to compensation
expense over the respective vesting or performance period. The unit options
issued to the non-employee directors of our Board of Directors have been
accounted for in accordance with APB No. 25.

The fair value of each unit option issued under the Omnibus Plan during the
quarter ended June 30, 2003, is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions: dividend yield of 8.75%; expected volatility of 30.77%; risk-free
interest rates of 3.31%; and expected lives of eight years. The fair value of
the unit options will be amortized over the two year vesting period.

The time-vested restricted units and the performance-based restricted units
were granted at a fair value of $36.69 per unit. The restrictions on the
time-vested units will lapse in four years from the date of grant and
restrictions on the performance-based restricted units will lapse upon us
achieving a specified level of target performance for identified greenfield
projects by June 1, 2007. If the target is not reached by June 1, 2007, the
units will be forfeited. The fair value of the time-vested restricted units is
being amortized over the four-year restricted period and the fair value of the
performance-based restricted units is being amortized over the performance
period. The performance-based restricted units are not entitled to any
distributions, nor do they have any voting rights, prior to the specified level
of target performance being achieved. The restricted units issued to
non-employee directors of our Board of Directors were issued at a fair value of
$36.35 per unit. This fair value is being amortized to compensation expense over
the period of service, which we have estimated to be one year.

Total unamortized deferred compensation as of June 30, 2003, was
approximately $1.7 million. Deferred compensation is reflected as a reduction of
partners' capital and is allocated 1% to our general partner and 99% to our
limited partners.

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4. EARNINGS PER COMMON UNIT

The following table sets forth the computation of basic and diluted
earnings per common unit (in thousands):

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

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6. FINANCING TRANSACTIONS

CREDIT FACILITIES

Our credit facility consists of two parts: a $600 million revolving credit
facility maturing in May 2004 and a $160 million senior secured term loan
maturing in 2007. Our credit facility and the GulfTerra Holding V, L.P.
(GulfTerra Holding) term credit facility are guaranteed by us and all of our
subsidiaries, except for our unrestricted subsidiaries, as detailed in Note 12,
and by GulfTerra Energy Finance Corporation and our general partner, and are
collateralized with substantially all of our assets (excluding the assets of our
unrestricted subsidiaries) and our general partner's general and administrative
services agreement. The interest rates we are charged on each of these credit
facilities are determined 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, the federal funds rate plus 0.5% or the Certificate of Deposit (CD)
rate as determined by JPMorgan Chase Bank increased by 1.00%); or (ii) LIBOR.

Our revolving credit facility, senior secured term loan and the GulfTerra
Holding term credit facility contain 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 restrict our ability to make
distributions to our unitholders.

Revolving Credit Facility

As of June 30, 2003, we had $415 million outstanding on our revolving
credit facility at an average interest rate of 3.43%. The total amount available
to us at June 30, 2003 under this facility was $155 million. The amounts
outstanding under this facility bear interest at our option at either (i) 0.75%
over the variable base rate described above; or (ii) 1.75% over LIBOR. We are
currently negotiating the renewal of our revolving credit facility to extend the
maturity date beyond May 2004 on terms not more restrictive than our existing
facility. We intend and believe we have the ability to renew this facility and
have continued to classify the facility as long-term debt in our balance sheet
as of June 30, 2003.

Senior Secured Term Loan

As of June 30, 2003, we had $157.5 million outstanding under our senior
secured term loan with an average interest rate of 4.75%. The amounts
outstanding under this senior secured term loan bear interest at our option at
either (i) 2.25% over the variable base rate described above; or (ii) 3.50% over
LIBOR.

GulfTerra Holding Term Credit Facility

As of June 30, 2003, the outstanding balance under the GulfTerra Holding
term credit facility was $160 million with an average interest rate of 3.60%.
The balance outstanding under the GulfTerra Holding term credit facility bears
interest at our option at either (i) 1.00% over the variable base rate described
above; or (ii) 2.25% over LIBOR. We repaid this term credit facility in July
2003 with proceeds from our issuance of $250 million 6 1/4% senior notes due
2010.

Senior Secured Acquisition Term Loan

As part of our November 2002 San Juan assets acquisition, we entered into a
$237.5 million senior secured acquisition term loan to fund a portion of the
purchase price. We repaid the senior secured acquisition term loan in March 2003
with proceeds from our issuance of $300 million 8 1/2% senior subordinated notes
due 2010. We recognized a loss of $3.8 million related to the write-off of
unamortized debt issuance costs. From the issuance of the senior secured
acquisition term loan in November 2002 to its repayment date, the interest rates
on our revolving credit facility and GulfTerra Holding term credit facility were
2.25% over the variable base rate described above or LIBOR increased by 3.50%.

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SENIOR NOTES

In July 2003, we issued $250 million in aggregate principal amount of
6 1/4% senior notes due June 2010, a new class of debt for us. The interest on
our senior notes is payable semi-annually in June and December with the
principal maturing in June 2010. Our senior notes are unsecured obligations that
rank equally with all of our existing and future senior debt, senior to all our
existing and future subordinated debt and junior in right of payment to all of
our existing and future senior secured debt.

We may redeem some or all of our senior notes, at our option, at any time
with at least 30 days notice at a price equal to the greater of (i) 100 percent
of the principal amount plus accrued interest, or (ii) the sum of the present
value of the remaining scheduled payments plus accrued interest. Our senior
notes are subject to a registration rights agreement under which we are required
to file an exchange offer registration statement with the SEC on or prior to
October 6, 2003. The registration statement must then become effective on or
prior to December 1, 2003 or we will be subject to additional interest until the
registration statement is declared effective. We used the proceeds of
approximately $245.1 million, net of issuance costs, to repay $160 million of
indebtedness under the GulfTerra Holding term credit facility and to temporarily
repay $85.1 million of the balance outstanding under our revolving credit
facility.

SENIOR SUBORDINATED NOTES

Each issue of our senior subordinated notes is subordinated in right of
payment to all existing and future senior debt including our existing credit
facilities and the senior notes we issued in July 2003.

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes. The interest on these notes is payable
semi-annually in June and December, and the notes mature in June 2010. We used
the proceeds of approximately $293 million, net of issuance costs, to repay
$237.5 million of indebtedness under our senior secured acquisition term loan
and to temporarily repay $55.5 million of the balance outstanding under our
revolving credit facility. In June 2003, we filed an exchange offer registration
statement with the SEC which became effective July 19, 2003. We may, at our
option, prior to June 1, 2006, redeem up to 33 percent of the originally issued
aggregate principal amount of these notes at a redemption price of 108.50
percent of the principal amount. On or after June 1, 2007, we may redeem all or
part of these notes at 104.25 percent of the principal amount.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on our fixed 8 1/2% $250 million senior subordinated
notes that were issued in May 2001. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% and receive a
fixed rate of 8 1/2%. We are accounting for this derivative as a fair value
hedge.

RESTRICTIVE PROVISIONS OF SENIOR AND SENIOR SUBORDINATED NOTES

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. 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
certain of our senior subordinated notes will be suspended should they be
similarly rated.

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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, is party to a $185
million credit agreement, under which it has $125 million outstanding at June
30, 2003, that may restrict its ability to pay distributions to its owners.
Beginning in April 2003, the additional interest Poseidon pays over LIBOR was
reduced from 1.50% to 1.25% as a result of improvement in Poseidon's debt ratio,
as defined in its credit agreement.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable portion of its LIBOR based interest rate on $75
million of the $125 million outstanding under its credit facility at 3.49%
through January 2004. The effective fixed interest rate on the hedged notional
amount currently is 4.74% (the variable LIBOR based rate of 3.49% plus the
margin of 1.25%). As of June 30, 2003, the remaining $50 million was at an
average interest rate of 2.49%.

Deepwater Gateway

As of June 30, 2003, Deepwater Gateway, an unconsolidated affiliate in
which we have a 50 percent joint venture ownership interest, had $109 million
outstanding under its construction loan at an average interest rate of 3.02%.
This construction loan will mature in July 2004 unless construction is completed
before that time and Deepwater Gateway meets other specified conditions, in
which case the construction loan will convert into a term loan with a final
maturity date of July 2009. Upon conversion of the construction loan to a term
loan, Deepwater Gateway will be required to maintain a debt service reserve
equal to or greater than the projected principal, interest and fees due on the
term loan for the immediately succeeding six month period. Prior to conversion
to the term loan Deepwater Gateway is prohibited from making distributions.

Cameron Highway

Cameron Highway Oil Pipeline Company (Cameron Highway), an unconsolidated
affiliate in which we have a 50 percent joint venture ownership interest (See
Note 10 for additional discussion relating to the formation of Cameron Highway),
entered into a $325 million project loan facility, consisting of a $225 million
construction loan and $100 million of senior secured notes.

The $225 million construction loan bears interest at Cameron Highway's
option at each borrowing at either (i) 2.00% over the variable base rate (equal
to the greater of the prime rate as determined by JPMorgan Chase Bank, the
federal funds rate plus 0.5% or the Certificate of Deposit (CD) rate as
determined by JPMorgan Chase Bank increased by 1.00%); or (ii) 3.00% over LIBOR.
Upon completion of the construction, the construction loan will convert to a
term loan maturing July 2008, subject to the terms of the loan agreement. At the
end of the first quarter following the first anniversary of the conversion into
a term loan, Cameron Highway will be required to make quarterly payments of
$8.125 million, with the remaining unpaid principal amount payable on the
maturity date. If the construction loan fails to convert into a term loan by
December 31, 2006, the construction loan and senior secured notes become fully
due and payable.

The interest rate on the notes will be at the 10-year U.S. Treasury
security rate plus 3.25%. Principal and interest payments of $4 million will be
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.

Under the terms of the project loan facility, Cameron Highway must pay each
of the lenders and the senior secured note holders commitment fees of 0.5% per
annum on any unused portion of such lender's or noteholder's committed funds.
The project loan facility as a whole is collateralized by (i) substantially all
of Cameron Highway's assets, including, upon conversion, a debt service reserve
capital account, and (ii) 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, as discussed in Note 10, the debt is
non-recourse to us. The construction loan and senior secured notes prohibit
Cameron Highway from making distributions to us

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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 next 5 years and in total thereafter are as
follows at June 30, 2003 (in thousands):

2003........................................................ $ 2,500
2004(1)..................................................... 420,146
2005........................................................ 165,000
2006........................................................ 5,000
2007........................................................ 140,000
Thereafter.................................................. 1,155,000
----------
Total long-term debt and other financing obligations,
including current maturities........................... $1,887,646
==========

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

(1) Balance includes our revolving credit facility; however, we are negotiating
the renewal to extend the maturity date beyond May 2004. We intend and
believe we have the ability to renew this facility and have continued to
classify the facility as long-term debt on our balance sheet as of June 30,
2003.

7. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we 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 of natural gas produced from royalty
properties 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). In May 2001, the court denied the defendants' motions to
dismiss. Discovery is proceeding. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.

Will Price (formerly Quinque). We have also been named defendants in
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. Quinque has been
dropped as a plaintiff and Will Price has been added. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
plaintiffs in this case seek certification of a nationwide class of natural gas
working interest owners and natural gas royalty owners to recover royalties that
the plaintiffs 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 was denied in
April 2003. Plaintiffs filed another amended petition to narrow the proposed
class to royalty owners in Kansas, Wyoming and Colorado and their motion was
granted on July 28, 2003. Our costs and legal exposure related to this lawsuit
and claims are not currently determinable.

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

15

acquisition date, including the legal matters involving Leapartners, L.P., City
of Edinburg, Houston Pipe Line Company LP, and City of Corpus Christi 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 has filed an appeal with the
Eighth Court of Appeals in El Paso, Texas. Briefs have been filed and oral
arguments were heard in November 2002. Review by the Court of Appeals is
expected in the third quarter of 2003.

Also, GulfTerra Texas Pipeline L.P., (GulfTerra Texas, formerly known as
EPGT Texas Pipeline L.P.) now owned by GulfTerra Holding, is involved in
litigation with the City of Edinburg concerning the City's claim that GulfTerra
Texas was required to pay pipeline franchise fees under a contract the City had
with Rio Grande Valley Gas Company, which was previously owned by GulfTerra
Texas and is now owned by Southern Union Gas Company. An adverse judgment
against Southern Union and GulfTerra Texas was rendered in Hidalgo County State
District court in December 1998 and found a breach of contract, and held both
GulfTerra Texas and Southern Union jointly and severally liable to the City for
approximately $4.7 million. The judgment relies on the single business
enterprise doctrine to impose contractual obligations on GulfTerra Texas and
Southern Union's entities that were not parties to the contract with the City.
GulfTerra Texas has appealed this case to the Texas Supreme Court seeking
reversal of the judgment rendered against GulfTerra Texas. The City seeks a
remand to the trial court of its claim of tortious interference against
GulfTerra Texas. Briefs have been filed and oral arguments were held in November
2002, and we are awaiting a decision.

In December 2000, a 30-inch natural gas pipeline jointly owned by GulfTerra
Intrastate, L.P. (GulfTerra Intrastate) now owned by GulfTerra Holding, and
Houston Pipe Line Company LP ruptured in Mont Belvieu, Texas, near Baytown,
resulting in substantial property damage and minor physical injury. GulfTerra
Intrastate is the operator of the pipeline. Two lawsuits were filed in the state
district court in Chambers County, Texas by eight plaintiffs, including two
homeowners' insurers. The suits seek recovery for physical pain and suffering,
mental anguish, physical impairment, medical expenses, and property damage.
Houston Pipe Line Company has been added as an additional defendant. In
accordance with the terms of the operating agreement, GulfTerra Intrastate has
agreed to assume the defense of and to indemnify Houston Pipe Line Company. As
of June 30, 2003, all but one claim has now been settled and these settlements
had no impact on our financial statements. The remaining claim relates solely to
property damages.

The City of Corpus Christi, Texas (the "City") is alleging that GulfTerra
Texas and various Coastal entities owe it monies for past obligations under City
ordinances that propose to tax GulfTerra Texas on its gross receipts from local
natural gas sales for the use of street rights-of-way. No lawsuit has been filed
to date. Some but not all of the GulfTerra Texas pipe at issue has been using
the rights-of-way since the 1960's. In addition, the City demands that GulfTerra
Texas agree to a going-forward consent agreement in order for the GulfTerra
Texas pipe and Coastal pipe to have the right to remain in City rights-of-way.

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 occuring 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 in this recently filed court action sued us in state district court
in Hardin County, Texas. The plaintiffs are the parents of John Christopher
Beverly, a two year
16

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
GulfTerra and BP, GulfTerra requested that BP indemnify GulfTerra for any
exposure. BP has thus far declined assuming the indemnity obligation. Our costs
and legal exposure related to this lawsuit and claims are not currently
determinable.

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. 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.

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, 2003, 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 will 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. As of June 30,
2003, we had a reserve of approximately $21 million for remediation costs
expected to be incurred over time associated with mercury meters. We assumed
this liability in connection with our April 2002 acquisition of the EPN Holding
assets. As part of the November 2002 San Juan assets acquisition, El Paso
Corporation has agreed to indemnify us for all the known and unknown
environmental liabilities related to the assets we purchased up to the purchase
price of $766 million. We will only be indemnified for unknown liabilities for
up to three years from the purchase date of this acquisition. In addition, we
have been indemnified by third parties for remediation costs associated with
other assets we have purchased. We expect to make capital expenditures for
environmental matters of approximately $10 million in the aggregate for the
years 2003 through 2007, primarily to comply with clean air regulations.

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
will 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
17

amounts accordingly. While there are still uncertainties relating to the
ultimate costs we may incur, based upon our evaluation and experience to date,
we believe our current reserves are adequate.

Rates and Regulatory Matters

Marketing Affiliate Notice of Proposed Rulemaking. In September 2001, the
Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed
Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct governing
the relationship between interstate pipelines and marketing affiliates to all
energy affiliates. Since our High Island Offshore System (HIOS) and Petal Gas
Storage facility, including the 59-mile Petal gas pipeline, are interstate
facilities as defined by the Natural Gas Act, the proposed regulations, if
adopted by FERC, would dictate how HIOS and Petal conduct business and interact
with all of our energy affiliates and El Paso Corporation's energy affiliates.
In December 2001, we filed comments with the FERC addressing our concerns with
the proposed rules. A public conference was held in May 2002, providing an
opportunity to comment further on the NOPR. Following the conference, we filed
additional comments. At this time, we cannot predict the outcome of the NOPR,
but adoption of the regulations in the form proposed would, at a minimum, place
additional administrative and operational burdens on us.

If the standards of conduct NOPR is adopted by the FERC, we will be
required to functionally separate our HIOS and Petal interstate facilities from
our other businesses. Under the proposed rule, we would be required to dedicate
employees to manage and operate our interstate facilities independently from our
other non-jurisdictional facilities. This employee group would be required to
function independently and would be prohibited from communicating non-public
transportation information to affiliates. Separate office facilities and systems
would be necessary because of the requirement to restrict affiliate access to
interstate transportation information. The NOPR also limits the sharing of
employees and officers with non-regulated entities. Because of the loss of
synergies and shared employee restrictions, a disposition of the interstate
facilities may be necessary for us to effectively comply with the rule. At this
time, we cannot predict the outcome of this NOPR.

Negotiated Rate Policy. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that sought comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. On July 25, 2003, the FERC issued
modifications to its negotiated rate policy applicable to interstate natural gas
pipelines. The new policy has two primary changes. First, the FERC will no
longer permit the pricing of negotiated rates based on natural gas commodity
price indices, although it will permit current contracts negotiated on that
basis to continue until the end of the applicable contract period. Second, the
FERC is imposing new filing requirements on pipelines to ensure the transparency
of negotiated rate transactions.

Interim Rule on Cash Management. In August 2002, the FERC issued a NOPR
proposing that all cash management or money pool arrangements between a
FERC-regulated subsidiary and its non-FERC regulated parent must be in writing
and that, as a condition of participating in a cash management or money pool
arrangement, the FERC-regulated entity maintain a minimum proprietary capital
balance of 30 percent and both it and its parent maintain investment grade
credit ratings. After receiving written comments and hearing industry
participant's concerns at a public conference in September 2002, the FERC issued
an Interim Rule on Cash Management in June 2003, which did not adopt the
proposed limitations on entry into or participation in cash management programs.
Instead, the Interim Rule requires natural gas companies to maintain up-to-date
documentation authorizing the establishment of the cash management program in
which they participate and supporting all deposits into, borrowings from,
interest income from, and interest expense to such program.

The Interim Rule seeks comments on a proposed requirement that mandates
FERC-regulated entities to file the cash management agreements with the FERC and
changes to the agreement within ten days and notify the FERC within 5 days when
its proprietary capital ratio falls below 30 percent (or conversely, its long-
term debt rises above 70 percent) and when it subsequently returns to or exceeds
30 percent. We filed comments on the Interim Rule on August 7, 2003. Under these
interim rules we believe that both HIOS and Petal will be able to continue to
participate in our cash management program.

Emergency Reconstruction of Interstate Natural Gas Facilities Final
Rule. On May 19, 2003, the FERC issued a Final Rule that amends its regulations
to enable natural gas interstate pipeline companies, in
18

emergency situations resulting in sudden unanticipated loss of natural gas or
capacity, to replace facilities when immediate action is required for the
protection of life or health or for the maintenance of physical property.
Specifically, the Final Rule permits a pipeline to replace mainline facilities
using a route other than an existing right-of-way, to commence construction
without being subject to a 45-day waiting period, and to undertake projects that
exceed the existing blanket cost constraints. Lastly, the Final Rule requires
that landowners be notified of potential construction but provides for a
possible waiver of the 30-day waiting period.

Pipeline Safety Notice of Proposed Rulemaking. In January 2003, the U.S.
Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Comments on the NOPR were
filed on April 30, 2003. At this time, we cannot predict the outcome of this
NOPR.

Financial Reporting Notice of Proposed Rulemaking. In June 2003, the FERC
issued a NOPR that proposes to establish quarterly financial reporting
requirements, which are similar to the current Annual Report but will require
the addition of Management's Discussion and Analysis, analysis of fourth quarter
results, revised officer certifications and electronic filing of auditor's
reports. The deadlines of these reports will be accelerated each year through
2006. Comments on this NOPR are due on August 22, 2003. At this time, we cannot
predict the outcome of this NOPR.

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. We have responded, and are
continuing to respond, as new requests are received, to the FERC staff's data
requests. The FERC has scheduled a hearing on this matter commencing November
17, 2003.

During the latter half of 2002, we experienced a significant variance
between the fuel usage on HIOS and the fuel collected from our customers. We
believe a series of events may have contributed to this variance, including two
major storms that hit the Gulf Coast Region (and these assets) in late September
and early October of 2002. We are taking numerous steps to determine the cause
of the fuel differences, including a review of receipt and delivery measurement
data. As of June 30, 2003, we had recorded fuel differences of approximately
$11.3 million, which is included in other non-current assets. Depending on the
outcome of our review, we expect to seek FERC approval to collect some or all of
the fuel differences. At this time we are not able to determine what amount, if
any, may be collectible from our customers. Any amount we are unable to resolve
or collect from our customers may negatively impact our earnings.

In June 2002, Petal Gas Storage, which is also subject to the FERC's
jurisdiction, filed with the FERC a certificate application to add additional
gas storage capacity to Petal's storage system. The filing included a new
storage cavern with a working gas capacity of 5 Bcf, the conversion and
enlargement of an existing subsurface brine storage cavern to a gas storage
cavern with a working capacity of 3 Bcf and related surface facilities, natural
gas, water and brine transmission lines. In February 2003, the FERC approved the
facilities proposed by Petal. We are currently in discussion with potential
customers for the proposed new capacity.

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
19

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. GulfTerra Texas' request
for rehearing has been granted and is pending before the FERC.

In July 2002, Falcon Gas Storage 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. 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 objected to
the changes, complaining that imbalance resolution is the lowest priority of
service. GulfTerra Texas responded to Falcon's objection and untimely
intervention, repeating its request that Falcon's intervention be dismissed.

In December 2002, GulfTerra Texas requested FERC approval of market-based
rates for interstate gas storage services performed at its Wilson storage
facility. The filing was in compliance with a requirement to rejustify its
existing rates or request new rates by December 20, 2002. Falcon also intervened
in this filing, complaining that market-based rates should be denied because of
their complaint about access on the GulfTerra Texas pipeline for third party
imbalance services. On May 15, 2003, the FERC approved Wilson's market based
rate proposal and dismissed Falcon's complaint.

Falcon Gas Storage Company, Inc. and its affiliate Hill-Lake Gas Storage,
L.P. ("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.

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 will have a material adverse effect on
our financial position, results of operations or cash flows. As new information
becomes available or relevant developments occur, we will establish accruals as
appropriate.

Joint Ventures

We conduct a portion of our business through joint venture arrangements 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.

Other Matters

As a result of current circumstances generally surrounding the energy
sector, the creditworthiness of several industry participants has been called
into question. As a result of these general circumstances, we have established
an internal group to monitor our exposure to and determine, as appropriate,
whether we should request prepayments, letters of credit or other collateral
from our counterparties.

8. 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 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.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices relating to gathering
activities in the San Juan Basin in anticipation of our acquisition of the San
Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby
we receive a fixed price of $3.525 per MMBtu and pay a floating price based on
the San Juan index. Beginning with the acquisition date in November 2002, we are
accounting for this derivative as a cash flow hedge under
20

SFAS No. 133. In February 2003, we entered into an additional derivative
financial instrument to continue to hedge our exposure during 2004 to changes in
natural gas prices relating to gathering activities in the San Juan Basin. The
derivative is a financial swap on 15,000 MMBtu per day whereby we receive a
fixed price of $3.95 per MMBtu and pay a floating price based on the San Juan
index. We are accounting for this derivative as a cash flow hedge under SFAS No.
133. As of June 30, 2003, the fair value of these cash flow hedges was a
liability of $10.3 million. For the six months ended June 30, 2003, we
reclassified a loss of approximately $6.0 million from accumulated other
comprehensive income resulting in a reduction to earnings. 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. We estimate the
entire amount will be reclassified from accumulated other comprehensive income
as a reduction to earnings over the next 18 months and approximately $9.7
million will be reclassified as a reduction to earnings over the next twelve
months.

Prior to June 30, 2003, 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 2002 and 2003 to offset the risk of
increasing natural gas prices. As of June 30, 2003, these cash flow hedges
expired and we reclassified a gain of approximately $0.2 million from
accumulated other comprehensive income to earnings. No ineffectiveness existed
in this hedging relationship because all purchase and sale prices were based on
the same index and volumes as the hedge transaction.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable portion of its LIBOR based interest rate on $75
million of its $185 million variable rate revolving credit facility at 3.49%
over the life of the swap. Prior to April 2003, under its credit facility,
Poseidon paid an additional 1.50% over the LIBOR rate resulting in an effective
interest rate of 4.99% on the hedged notional amount. Beginning in April 2003,
the additional interest Poseidon pays over LIBOR was reduced resulting in an
effective fixed interest rate of 4.74% on the hedged notional amount. As of June
30, 2003, the fair value of its interest rate swap was a liability of $0.9
million resulting in accumulated other comprehensive loss of $0.9 million. We
included our 36 percent share of this liability of $0.3 million as a reduction
of our investment in Poseidon and as a loss in accumulated other comprehensive
income which we estimate will be reclassified to earnings proportionately over
the next six months. Additionally, we have recognized in income our 36 percent
share of Poseidon's realized loss of $0.7 million for the six months ended June
30, 2003, or $0.2 million, through our earnings from unconsolidated affiliates.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on our fixed 8 1/2% $250 million senior subordinated
notes that were issued in May 2001. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% and receive a
fixed rate of 8 1/2%. We are accounting for this derivative as a fair value
hedge.

The counterparty for our San Juan hedging activities is J. Aron and
Company, a subsidiary of Goldman Sachs. We do not require collateral and do not
anticipate non-performance by this counterparty. The counterparty for Poseidon's
hedging activity is Credit Lyonnais. Poseidon does not require collateral and
does not anticipate non-performance by this counterparty. Wachovia Bank is our
counterparty on our new interest rate swap and we do not require collateral nor
anticipate non-performance by this counterparty.

9. 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.

21

As a result of our sale of the Prince TLP and our nine percent overriding
royalty interest in the Prince Field in April 2002, the results of operations
from these assets are reflected as discontinued operations in our statements of
income for all periods presented. Accordingly, the segment results do not
reflect the results of operations for the Prince assets.

We measure segment performance using earnings before interest, income
taxes, depreciation and amortization (EBITDA), which we formerly referred to as
"Performance Cash Flows," or an asset's ability to generate income. EBITDA is
used in the evaluation of our businesses and should not be considered as an
alternative to net income as an indicator of our operating performance. EBITDA
may not be a comparable measurement among different companies.

Following are results as of and for the periods ended June 30:

- ----------

(1) Represents predominately our oil and natural gas production activities as
well as intersegment eliminations.

22

- ----------

(1) Represents predominately our oil and natural gas production activities as
well as intersegment eliminations.

A reconciliation of our segment EBITDA to our net income is as follows:

23

10. 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, 2003
(IN THOUSANDS)

SIX MONTHS ENDED JUNE 30, 2002
(IN THOUSANDS)

- ----------

(1) 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.

In June 2003, we formed Cameron Highway Oil Pipeline Company and
contributed to this newly formed company the $458 million Cameron Highway oil
pipeline system construction project. Cameron Highway is responsible for
building and operating the pipeline, which is scheduled for completion during
the third quarter of 2004.
24

In connection with the construction of the Cameron Highway oil pipeline, we
entered into producer agreements with three major anchor producers, BP
Exploration & Production Company (BP Exploration), BHP Billiton Petroleum
(Deepwater), Inc. (BHP), and Union Oil Company of California (Unocal), which
agreements were assigned to and assumed by Cameron Highway. The producer
agreements require construction of the 390-mile Cameron Highway oil pipeline. We
are obligated to make additional capital contributions to Cameron Highway, to
the extent that the construction costs for the pipeline exceed Cameron Highway's
capital resources, including our initial equity contributions and proceeds from
Cameron Highway's project loan facility.

In July 2003, we sold a 50 percent interest in Cameron Highway to Valero
Energy Corporation 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. In July 2003, we recognized $19 million as a gain from the sale of
long-lived assets. In addition, Valero will pay us a total of $16 million, $5
million to be paid once the system is completed and the remaining $11 million by
the end of 2006. We expect to reflect the receipts of these additional amounts
in the periods received as gains from the sale of long-lived assets in our
income statement. In connection with the formation of the Cameron Highway joint
venture, Valero agreed to pay their proportionate share of pipeline construction
costs that exceed Cameron Highways's capital resources, including the initial
equity contributions and proceeds from Cameron Highway's project loan facility.

The Cameron Highway oil pipeline system project is expected to be funded
with 29 percent equity through capital contributions from the Cameron Highway
partners and 71 percent debt through a $325 million project loan facility,
consisting of a $225 million construction loan and $100 million of senior
secured notes. See Note 6 for additional discussion of the project loan
facility.

11. RELATED PARTY TRANSACTIONS

Our transactions with related parties and affiliates are as follows:

There have been no changes to our related party relationships, except as
described below, from those described in Note 9 of our audited financial
statements filed in our 2002 Form 10-K.

Revenues received from related parties for the quarters ended June 30, 2003
and 2002, were approximately 11 percent and 48 percent of our total revenue.
Revenues received from related parties for the six months ended June 30, 2003
and 2002, were approximately 11 percent and 43 percent of our total revenue.
Revenues received from El Paso Field Services increased $8.5 million from the
first quarter of 2003 primarily as a result of higher natural gas and NGL
volumes sold to El Paso Field Services from our Big Thicket assets

25

and from higher volumes on the Texas NGL assets that were reactivated in 2003.
Also, we have undertaken efforts to reduce our transactions with El Paso
Merchant Energy North America Company (Merchant Energy) and as of June 30, 2003,
we have replaced all our month-to-month arrangements with similar arrangements
with third parties.

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

At June 30, 2003, and December 31, 2002, our accounts receivable due from
related parties was $61.3 million and $83.8 million. At June 30, 2003 and
December 31, 2002, our accounts payable due to related parties was $80.8 million
and $86.1 million.

26

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:

Other Matters

In connection with the sale of some of our Gulf of Mexico assets in January
2001, El Paso Corporation agreed to make quarterly payments to us of $2.25
million for three years beginning March 2001 and $2 million in the first quarter
of 2004. The present value of the amounts due from El Paso Corporation were
classified as follows:

27

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 indemnified us for specific litigation matters to the
extent the ultimate resolutions of these matters result in judgments against us.
For a further discussion of these matters see Note 7, Commitments and
Contingencies, Legal Proceedings. Some of our agreements obligate certain
indirect subsidiaries of El Paso Corporation to pay for capital costs related to
maintaining assets which were acquired by us, if such costs exceed negotiated
thresholds. We have made no such claims for reimbursement to date but may make
claims based on our 2002 expenditures and on our expected 2003 expenditure
requirements.

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 agreements to receive from
subsidiaries of El Paso Corporation the following: $2 million from Tennessee Gas
Pipeline for our Medusa project, $7.0 million from El Paso Field Services for
the Marco Polo pipeline and $6.1 million from ANR Pipeline Company for our
Phoenix project. Regulated pipelines often contribute capital toward the
construction costs of gathering facilities owned by others which are, or will
be, connected to their pipelines. El Paso Field Services' contribution is in
anticipation of additional natural gas that will flow through to its onshore
natural gas processing facilities.

12. GUARANTOR FINANCIAL INFORMATION

As of June 30, 2003, our revolving credit facility, GulfTerra Holding term
credit facility and senior secured term loan are guaranteed by each of our
subsidiaries, excluding our unrestricted subsidiaries (Matagorda Island Area
Gathering System, Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.,
Cameron Highway Pipeline GPI, L.L.C. (CHOPS GPI), Cameron Highway Pipeline II,
L.P. (CHOPS II), Cameron Highway Pipeline III, L.P. (CHOPS III), and Cameron
Highway Oil Pipeline Company (Cameron Highway), and our general partner, and are
collateralized by our general partner's general and administrative services
agreement and substantially all of our assets. In addition, all of our senior
subordinated notes are jointly, severably, fully and unconditionally guaranteed
by us and all of our subsidiaries, excluding our unrestricted subsidiaries. As
part of our Cameron Highway transaction, in July 2003 we sold CHOPS GPI, CHOPS
II and CHOPS III and, as a result, Cameron Highway became an unconsolidated
affiliate in which we have a 50 percent joint venture ownership interest. 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.

Non-guarantor subsidiaries as of and for the quarter and six months ended
June 30, 2003, consisted of our unrestricted subsidiaries. Non-guarantor
subsidiaries as of and for the quarter ended June 30, 2002, consisted of our
GulfTerra Holding Subsidiaries, which own the EPN Holding assets and equity
interests in GulfTerra Holding. Non-guarantor subsidiaries for the quarter ended
March 31, 2002 consisted of Argo and Argo I which owned the Prince TLP. As a
result of our disposal of the Prince TLP and our related overriding royalty
interest in April 2002, the results of operations and net book value of these
assets are reflected as discontinued operations in our statements of income and
assets held for sale in our balance sheets and Argo and Argo I became guarantor
subsidiaries.

28

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

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE QUARTER ENDED JUNE 30, 2002

29

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

30

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 2002

31

CONDENSED CONSOLIDATING BALANCE SHEETS
JUNE 30, 2003

32

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2002

33

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

34

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2002

35

13. NEW ACCOUNTING PRONOUNCEMENTS

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. This statement amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. The statement is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003, except for provisions that relate to SFAS No. 133 implementation
issues that have been effective for the fiscal quarter that began prior to June
15, 2003, which are applicable on their respective effective dates. We are
required to adopt the provisions of this statement prospectively, unless
otherwise prescribed. We have adopted this pronouncement on a prospective basis
as of July 1, 2003.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. This statement
provides guidance on the classification of financial instruments, as equity, as
liabilities, or as both liabilities and equity. The provisions of SFAS No. 150
are effective for all financial instruments entered into or modified after May
31, 2003, and otherwise is effective at the beginning of the first interim
period beginning July 1, 2003. We adopted the provisions of SFAS No. 150 on July
1, 2003, and our adoption had no material impact on our financial statements.

36

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 for the year ended December 31, 2002, in addition to
the interim financial statements and notes presented in Item 1 of this Quarterly
Report on Form 10-Q.

GENERAL PARTNER RELATIONSHIP

Our corporate governance structure and independence initiatives

This year we have continued to improve our corporate governance model,
which currently meets the standards established by the SEC and the NYSE. During
the first quarter of 2003, we identified and evaluated a number of changes that
could be made to our corporate structure to better address potential conflicts
of interest and to better balance the risks and rewards of significant
relationships with our affiliates, which we refer to as Independence
Initiatives. Through July 2003, we have implemented the following:

- added an additional independent director to our board of directors,
bringing the number of independent directors to four of the six-member
board;

- established a governance and compensation committee of our board of
directors consisting solely of independent directors which is responsible
for establishing performance measures and making recommendations to El
Paso Corporation concerning total compensation of its employees
performing duties for us;

- changed our name to GulfTerra Energy Partners, L.P.;

- received a letter of credit from El Paso Merchant Energy North America
totaling $5.1 million regarding our existing customer/contractual
relationships with them;

- modified our partnership agreement to: (1) eliminate El Paso
Corporation's right to vote its common units with respect to the removal
of the general partner; (2) effectively reduce the third party common
unit vote required to remove the general partner from 72 percent to 67
percent; and (3) require the unanimous vote of the general partner's
board of directors before the general partner or we can voluntarily
initiate bankruptcy proceedings;

- completed a resource support agreement with El Paso Corporation; and

- reorganized our structure, further reducing our interrelationships with
El Paso Corporation, resulting in our general partner being a Delaware
limited liability company that is not permitted to have:

- material assets other than its interests in us;

- material operations other than those relating to our operations;

- material debt or other obligations other than those owed to us or our
creditors;

- material liens other than those securing obligations owed to us or our
creditors; or

- employees.

We are in the process of implementing the following Independence
Initiatives:

- adding one more independent director to the board of directors, and

- negotiating a master netting agreement that could partially mitigate our
risks associated with our ongoing contractual arrangements with El Paso
Corporation or any of its subsidiaries. Approval must be received from
our general partner's board of directors and from El Paso Corporation
prior to executing the master netting agreement.

Under the partnership agreement, our general partner has the responsibility
to, among other things, manage and operate our assets. In addition, our general
partner had agreed not to voluntarily withdraw as

37

general partner prior to December 31, 2002. Now that this obligation of the
general partner has expired, our general partner can withdraw with 90 days
notice. We have no employees today, a condition that is common among MLPs.
Although this arrangement has worked well for us in the past and continues to
work well for us, we are evaluating the direct employment of the personnel who
manage the day-to-day operations of our assets.

Our relationship with El Paso Corporation

El Paso Corporation, a NYSE-listed company, is a leading provider of
natural gas services and the largest pipeline company in North America. Through
its subsidiaries, El Paso Corporation:

- owns 100 percent of our general partner, which means that, historically,
El Paso Corporation and its affiliates have employed the personnel who
operate our businesses. We reimburse our general partner and its
affiliates for the costs they incur on our behalf, and we pay our general
partner its proportionate share of distributions --relating to its one
percent general partnership interest and the related incentive
distributions --we make to our partners each calendar quarter. Furthering
our Independence Initiatives efforts, El Paso Corporation has announced
its intention to sell between 5 and 10 percent of its ownership interest
in our general partner to a third party. El Paso Corporation has the sole
responsibility to determine the ultimate ownership status of the general
partner interest.

- is a significant stake-holder in us -- it owns approximately 23.4
percent, or 11,674,245, of our common units (decreased from 26.5 percent
as a result of our common unit offerings during the second quarter 2003),
all 10,937,500 of our Series C units, which we issued in November 2002
for $350 million, all 124,014 of our outstanding Series B preference
units, with a liquidation value of approximately $163.6 million at June
30, 2003 and our one percent general partner interest. As holders of some
of our common units and all of our Series C units, subsidiaries of El
Paso Corporation receive their proportionate share of distributions we
make to our partners each calendar quarter. In July 2003, we filed a
registration statement on Form S-3 to register for resale 2,000,000 of
the common units owned by affiliates of El Paso Corporation.

- is a customer of ours. As with other large energy companies, we have
entered into a number of contracts with El Paso Corporation and its
affiliates.

As discussed previously, we have implemented, and are in the process of
implementing, a number of Independence Initiatives that are designed to help us
better manage the rewards and risks relating to our relationship with El Paso
Corporation. However, even in the light of these Independence Initiatives or any
other arrangements, we may still be adversely affected if El Paso Corporation
continues to suffer financial stress.

RELATED PARTY TRANSACTIONS

In our normal course of business we enter into transactions with various
entities controlled directly or indirectly by El Paso Corporation.

Revenues received from El Paso Field Services increased by $8.5 million
from the first quarter of 2003 primarily as a result of higher natural gas and
NGL volumes sold to El Paso Field Services from our Big Thicket assets and from
higher volumes on the Texas NGL assets that were reactivated in 2003.

For the quarter ended June 30, 2003, $7.8 million of our related party
revenue came from Merchant Energy. In November 2002, El Paso Corporation
announced its intention to exit the energy trading business. As of June 30,
2003, we have replaced all our month-to-month, market priced sales of natural
gas to Merchant Energy with similar arrangements with third parties. In the
quarter ended June 30, 2003, these natural gas transportation and storage
agreements represented revenue of approximately $7.7 million. Currently, we have
a $5.1 million letter of credit from Merchant Energy representing two months of
transportation revenues. As of July 2003, Merchant Energy continues to fully
utilize these agreements; however, Merchant Energy has agreed to transfer the
natural gas transportation and storage agreements they have with us to El Paso
Field Services. This transfer is expected to be completed by year end.

38

In connection with our San Juan assets acquisition, we entered into a
10-year transportation agreement with El Paso Field Services beginning January
1, 2003. Under this agreement, we receive a fee of $1.5 million per year for
transportation on one of our NGL pipelines.

See Part I, Financial Information, Note 11 for a further discussion of our
related party transactions.

LIQUIDITY AND CAPITAL RESOURCES

The ability to execute our growth strategy and complete our projects is
dependent upon our access to the capital necessary to fund the 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.

CAPITAL RESOURCES

As part of our previously announced strategy for 2003 to raise
approximately $300 million through the issuance of common units and other
equity, we have received net proceeds totaling $181.7 million through the
issuance of approximately 5,718,881 common units since January 1, 2003 from the
following offerings:

We used the net proceeds from our common unit offerings to temporarily
reduce amounts outstanding under our $600 million revolving credit facility and
for general partnership purposes.

SERIES B PREFERENCE UNITS

In connection with our second quarter 2003 public offerings of common
units, our general partner, in lieu of a cash contribution, contributed to us,
and we retired, 1,378 Series B preference units with liquidation value of
approximately $1.8 million, including accrued distributions of approximately
$0.4 million, to maintain its one percent general partner interest.

SERIES F CONVERTIBLE UNITS

In connection with our public offering of 1,118,881 common units in May
2003, we issued 80 Series F convertible units. Each Series F convertible unit is
comprised of two separate detachable units -- a Series F1 convertible unit and a
Series F2 convertible unit -- that have identical terms except for vesting and
termination times and the number of underlying common units into which they may
be converted. The Series F1 units are convertible into up to $80 million of
common units anytime after August 12, 2003, and until March 29, 2004 (subject to
defined extension rights). The Series F2 units are convertible into up to $40
million of common units provided at least $40 million of Series F1 convertible
units are converted prior to their termination. The Series F2 units terminate on
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 of the prevailing price (as defined below), if the prevailing price is
equal to or greater than $35.75 or 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
39

average closing price of our common units for the last seven days of the 60 day
period included in (i). If they had been eligible for conversion, the price at
which the Series F convertible units could have been converted to common units,
based on the previous 60 business days at June 30, 2003 and August 7, 2003, was
$29.67 and $36.15. The Series F units may be converted into a maximum of
8,329,679 common units and are not entitled to any dividends or distributions,
nor do they have any voting rights prior to conversion. The value associated
with the Series F convertible units is included in partners' capital as a
component of common units.

The Series F convertible units have a feature which allows us to establish
a minimum conversion unit price. Should the actual conversion unit price be
below the minimum conversion unit price, we would be required to settle the
conversion in cash in lieu of issuing common units. Currently, no minimum
conversion unit price has been established; however, if a minimum conversion
unit price is established, we may have to change our accounting treatment for
the Series F convertible units to account for them as a derivative under the
provisions of SFAS No. 133 and record an asset or liability for the fair value
of the Series F convertible units and the changes in fair value would impact our
earnings.

FORECASTED EXPENDITURES

We estimate our forecasted expenditures based upon our strategic operating
and growth plans, which are also dependent upon our ability to produce or
otherwise obtain the capital necessary to accomplish our operating and growth
objectives. These estimates may change due to factors beyond our control, such
as weather related issues, changes in supplier prices or poor economic
conditions. Further, estimates may change as a result of decisions made at a
later date, which may include acquisitions, scope changes or decisions to take
on additional partners. Our projection of expenditures for the quarters ended
June 30 and March 31, 2003 as presented in our 2002 Annual Report on Form 10-K,
were $92 and $120 million; however, our actual expenditures were approximately
$125 and $80 million.

The table below depicts our estimate of projects and capital maintenance
expenditures through June 30, 2004 (in millions). These expenditures are net of
anticipated project financings, contributions in aid of construction and
contributions from joint venture partners, including the recently announced
joint venture with Valero for the development of our Cameron Highway oil
pipeline project and related project financing to fund a portion of the
construction costs. 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.

40

DEBT REPAYMENT AND OTHER OBLIGATIONS

See Part I, Financial Information, Note 6, for a detailed discussion of our
debt obligations.

The following table presents the timing and amounts of our debt repayment
and other obligations for the years following June 30, 2003, that we believe
could affect our liquidity (in millions):

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

(1) Assumes the new maturity date for our revolving credit agreement is in 2006.

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes due June 2010. We used the proceeds of
approximately $293 million, net of issuance costs, to repay $237.5 million of
indebtedness under our senior secured acquisition term loan and to temporarily
repay $55.5 million of the balance outstanding under our revolving credit
facility.

Following our March 2003 repayment of the senior secured acquisition term
loan, the amounts outstanding under our revolving credit facility bear interest,
at our option, at either (i) 0.75% over the variable base rate (equal to the
greater of the prime rate as determined by JPMorgan Chase Bank, the federal
funds rate plus 0.5% or the Certificate of Deposit (CD) rate as determined by
JPMorgan Chase Bank plus 1.00%); or (ii) 1.75% over LIBOR. For the GulfTerra
Holding term credit facility, the amounts outstanding bear interest at 1% over
the variable rate described above or LIBOR increased by 2.25%. Prior to our
repayment of the senior secured acquisition term loan, the revolving credit
facility and the GulfTerra Holding term credit facility both bore interest at
2.25% over the variable rate described above or LIBOR increased by 3.50%.

In July 2003, we issued $250 million in aggregate principal amount of our
6 1/4% senior notes due 2010. We used the proceeds of approximately $245.1
million, net of issuance costs, to repay the $160 million of indebtedness under
the GulfTerra Holding term credit facility and the remaining $85.1 million to
temporarily reduce amounts outstanding under our revolving credit facility.

In July 2003, Cameron Highway Oil Pipeline Company, our 50 percent owned
joint venture that is constructing the 390-mile Cameron Highway Oil Pipeline,
entered into a $325 million project loan facility consisting of a $225 million
construction loan and $100 million of senior secured notes. See Part I,
Financial Information, Note 6 for further discussion.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on our fixed 8 1/2% $250 million senior subordinated
notes that were issued in May 2001. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% and receive a
fixed rate of 8 1/2%. We are accounting for this derivative as a fair value
hedge.

41

We are currently negotiating the renewal of our revolving credit facility
to extend the maturity date beyond May 2004 on terms not more restrictive than
our existing facility. We intend, and believe we have the ability, to renew this
facility and have therefore reflected the outstanding balance as long term.

We expect to use the proceeds we receive from any additional capital we
raise through the issuance of additional common units to reduce amounts
outstanding under our credit facilities, to finance growth opportunities and for
general partnership purposes. Our ability to raise additional capital may be
negatively affected by many factors, including our relationship with El Paso
Corporation.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $134.2 million for the six
months ended June 30, 2003, compared to $61.6 million for the same period in
2002. The increase was attributable to operating cash flows generated by our
acquisitions of the EPN Holding assets in April 2002 and the San Juan assets in
November 2002.

CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities was approximately $204.0 million for
the six months ended June 30, 2003. Our investing activities include capital
expenditures related to the construction of the Marco Polo pipelines, the
Cameron Highway oil pipeline, and the Falcon Nest fixed-leg platform.

CASH FROM FINANCING ACTIVITIES

Net cash provided by financing activities was approximately $51.4 million
for the six months ended June 30, 2003. During 2003, our cash provided by
financing activities included issuances of long-term debt and offerings of
common units and convertible units. Cash used in our financing activities
included repayments on our senior secured acquisition term loan, our revolving
credit facility and other financing obligations, as well as distributions to our
partners.

ACQUISITION

During the six months ended June 30, 2003, the total purchase price and net
assets acquired for the April 2002 EPN Holding asset acquisition increased $17.5
million due to post-closing purchase price adjustments related primarily to
natural gas imbalances assumed in the transaction. The following table
summarizes our allocation of the fair values of the assets acquired and
liabilities assumed. Our allocation among the assets acquired is based on the
results of an independent third-party appraisal.

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CONSTRUCTION PROJECTS

We are currently constructing, among others, the following projects:

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

(1) Includes 100% 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 from subsidiaries of El Paso Corporation the
following: $2 million from Tennessee Gas Pipeline for our Medusa project,
$7.0 million from El Paso Field Services for the Marco Polo pipeline and
$6.1 million from ANR Pipeline Company for our Phoenix project. We have
received $10.5 million from ANR Pipeline Company for the Marco Polo
pipeline.

(2) GulfTerra expenditures are net of anticipated or received contributions in
aid of construction, project financings and contributions from joint venture
partners to the extent applicable.

(3) Forecasted expenditures increased during the first quarter of 2003 due to
increases in gas processing capacity (from 250 to 300 MMcf/d) and oil
processing capacity (from 100 to 120 MBbls/d) and a higher builder's risk
insurance cost.

(4) In July 2003, we announced the completion of agreements to form a 50/50
joint venture with Valero Energy Corporation. Valero paid us approximately
$51 million at closing representing 50 percent of the capital investment
expended through that date.

PROJECTS ANNOUNCED IN 2003

San Juan Optimization Project. In May 2003, we announced the approval of a
$43 million project relating to our San Juan Basin assets. The project is
expected to be completed in stages through 2006. The project is expected to
result in a 130 MMcf/d increase in capacity, added compression to the Chaco
processing facility and increased market opportunities through a new
interconnect at the tailgate of the Chaco processing facility. As of June 30,
2003, we have spent approximately $0.6 million related to this project.

OTHER MATTERS

As a result of current circumstances generally surrounding the energy
sector, the creditworthiness of several industry participants has been called
into question, including El Paso Corporation, the indirect parent of our general
partner. As a result of these general circumstances, we have established an
internal group to monitor our exposure to, and determine, as appropriate,
whether we should request prepayments, letters of credit or other collateral
from our counterparties. During the second quarter of 2003, we received a letter
of credit from Merchant Energy totaling $5.1 million regarding our existing
customer/contractual relationships with them. If these general conditions worsen
and, as a result, several industry participants file for Chapter 11 bankruptcy
protection, it could have a material adverse effect on our financial position,
results of operations or cash flows. While some industry participants have filed
for Chapter 11 bankruptcy protection during the past six months, our exposure to
these participants has not been significant. However, based upon our review of
the collectibility of accounts receivable, we increased our allowance by $2.0
million during the second quarter of 2003. As of June 30, 2003 and December 31,
2002, our allowance was $4.5 million and $2.5 million.

43

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.

As a result of our sale of the Prince TLP and our nine percent overriding
interest in the Prince Field in April 2002, the results of operations from these
assets are reflected as discontinued operations in our statements of income for
all periods presented and are not reflected in our segment results below.

To the extent possible, results of operations have been reclassified to
conform to the current business segment presentation, although these results may
not be indicative of the results which would have been achieved had the revised
business segment structure been in effect during those periods. 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 Part I, Financial Information, Note 9.

We use earnings before interest, income taxes, depreciation and
amortization (EBITDA) to assess our consolidated and segment results. EBITDA is
our liquidity measure as our lenders are interested in whether we generate
sufficient cash to meet our debt obligations as they become due. Accordingly,
our revolving credit agreement and indentures utilize EBITDA to represent a
measure of the cash flows from current operations. Our equity investors
generally focus on our capacity to pay distributions or to grow the business, or
both. As a result, our ability to generate cash from operations of the business
to cover distributions, debt service, as well as to pursue growth opportunities,
is an important measure of our liquidity. A reconciliation of this measure to
cash flows from operations for our consolidated results is as follows:

44

SEGMENT RESULTS

The following table presents EBITDA by segment and in total.

See Item 1, Financial Information, Note 9 for a reconciliation of segment
EBITDA to net income.

NATURAL GAS PIPELINES AND PLANTS

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

(1) Earnings from unconsolidated affiliates for the quarter and six months ended
June 30, 2003, was $626 thousand and $1,255 thousand.

Transportation agreements with some of our customers require that we
purchase natural gas from producers at the wellhead for an index price less an
amount that compensates us for gathering services. We then sell the natural gas
into the open market at points on our system at the same index price.
Accordingly, our operating revenues and costs of natural gas are impacted by
changes in energy commodity prices, while our margin is unaffected by these
contracts. For these reasons, we believe that gross margin (revenue less cost

45

of natural gas) provides a more accurate and meaningful basis than operating
revenue or cost of natural gas for analyzing operating results for this segment.

Second Quarter Ended June 30, 2003 Compared With Second Quarter Ended June 30,
2002

Natural gas pipelines and plants margin for the quarter ended June 30,
2003, was $45.5 million higher than in the same period in 2002. Our San Juan
Basin assets, acquired in November 2002, accounted for approximately $42.5
million of the increase. Margin also increased by approximately $2.3 million due
to an increase in volumes attributable to a full quarter of results from our
Falcon Nest Pipeline, which was placed in service in March 2003 and additional
volumes on our Viosca Knoll system from the Canyon Express pipeline system.
Additionally, margin increased by $2.0 million due to higher NGL prices in 2003,
which favorably impacted our processing margins in the Permian Basin region.
Partially offsetting these increases was a $3.2 million decrease in margin for
our Texas intrastate pipeline attributable to the impact that higher natural gas
prices in 2003 had on our fuel costs and the revaluation of our natural gas
imbalances.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter ended June 30, 2003, were $15.3 million higher than the same period
in 2002 primarily due to the acquisition of the San Juan Basin assets. Excluding
the operating costs of these acquired assets, operating expenses increased by
$9.5 million primarily due to an increase in our allowance for doubtful accounts
of $2.0 million, higher repair and maintenance expenses of $3.1 million on our
Texas intrastate pipeline, which were unusually low in the prior year quarter
due to timing of expenditures, and a $3.6 million increase associated with our
general and administrative services agreement with subsidiaries of El Paso
Corporation. This increase is a result of our acquisitions in 2002.

Six Months Ended June 30, 2003 Compared With Six Months Ended June 30, 2002

Natural gas pipelines and plants margin for the six months ended June 30,
2003, was $124.7 million higher than in the same period in 2002. Our San Juan
Basin assets, acquired in November 2002, and our EPN Holding assets, acquired in
April 2002, accounted for approximately $85.4 million and $36.6 million of the
increase. Additionally, margin increased by $1.7 million due to a full quarter
of results from our Falcon Nest Pipeline which was placed in service in March
2003. Margin also increased by $2.0 million due to higher NGL prices in 2003,
which favorably impacted our processing margins in the Permian Basin region and
by approximately $2.5 million due to increased volumes on our Viosca Knoll
system from the Canyon Express pipeline system, which was placed into service in
September 2002. Offsetting these increases were a $3.2 million decrease in
margin for our Texas intrastate pipeline system attributable to the impact that
higher natural gas prices in 2003 had on our fuel costs and the revaluation of
our natural gas imbalances and $2.2 million of decreased production on HIOS due
to natural decline in the offshore region.

Operating expenses excluding depreciation, depletion, and amortization for
the six months ended June 30, 2003, were $37.7 million higher than the same
period in 2002 primarily due to the acquisitions of the San Juan Basin and EPN
Holding assets. Excluding the operating costs of these acquired assets,
operating expenses increased by $18.0 million primarily due to an increase in
our allowance for doubtful accounts of $2.0 million, higher repair and
maintenance expenses of $3.1 million on our Texas intrastate pipeline, which
were unusually low in 2002 due to timing of expenditures, and a $10.2 million
increase associated with our general and administrative services agreement with
subsidiaries of El Paso Corporation. This increase is a result of our
acquisitions in 2002.

46

OIL AND NGL LOGISTICS

- ----------

(1) Earnings from unconsolidated affiliates for the quarter and six months ended
June 30, 2003, was $2,361 thousand and $5,048 thousand. Earnings from
unconsolidated affiliates for the quarter and six months ended June 30,
2002, was $4,012 thousand and $7,373 thousand.

(2) Represents 100% of the volumes flowing through the pipeline.

Transportation agreements with some of our customers require that we
purchase the oil produced at the inlet of our pipeline for an index price less
an amount that compensates us for transportation services. At the outlet of our
pipeline, we resell this oil back to these producers at the same index price. We
reflect these sales in gathering and processing revenues and the related
purchases as cost of oil. For these reasons, we believe that gross margin
(revenue less cost of oil) provides a more accurate and meaningful basis than
operating revenue or cost of oil for analyzing operating results for this
segment.

Second Quarter Ended June 30, 2003 Compared With Second Quarter Ended June 30,
2002

For the quarter ended June 30, 2003, margin was $6.2 million higher than
the same period in 2002. Our Texas NGL assets and Typhoon Oil Pipeline, acquired
in November 2002, contributed approximately $8.2 million to the increase.
Partially offsetting this increase was a $1.7 million decline in margin for our
transportation and fractionation assets. Our fractionation volumes decreased due
to weak demand for NGLs and poor processing economics that reduced the amount of
NGLs that were recovered at the natural gas processing plants connected to our
NGL fractionation assets. The poor processing economics are largely driven by
higher natural gas prices relative to NGL prices in 2003.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter ended June 30, 2003, were $3.2 million higher than the same period
in 2002 primarily due to our November 2002 acquisition of the Typhoon Oil
Pipeline and the Texas NGL assets.

Other income for the quarter ended June 30, 2003, was $1.6 million lower
than the same period in 2002 due to a decrease in cash distributions from our
unconsolidated affiliate Poseidon Oil Pipeline Company. Poseidon Oil Pipeline
Company experienced lower earnings due to natural production declines on some of
the older deepwater fields, as well as production downtime at several new
fields.

47

Six Months Ended June 30, 2003 Compared With Six Months Ended June 30, 2002

For the six months ended June 30, 2003, margin was $9.3 million higher than
the same period in 2002. Our Texas NGL assets and Typhoon Oil Pipeline, acquired
in November 2002, contributed approximately $11.1 million to the increase.
Partially offsetting this increase was a $1.9 million decline in margin for our
transportation and fractionation assets. Our fractionation volumes decreased due
to weak demand for NGL and poor processing economics that reduced the amount of
NGL that were recovered at the natural gas processing plants connected to our
NGL fractionation assets. The poor processing economics are largely driven by
higher natural gas prices relative to NGL prices in 2003.

Operating expenses excluding depreciation, depletion, and amortization for
the six months ended June 30, 2003 were $4.9 million higher than the same period
in 2002, primarily due to our November 2002 acquisition of the Typhoon Oil
Pipeline and the Texas NGL assets.

Other income for the six months ended June 30, 2003, was $2.3 million lower
than the same period in 2002 due to a decrease in cash distributions from our
unconsolidated affiliate Poseidon Oil Pipeline Company. Poseidon Oil Pipeline
Company experienced lower earnings due to natural production declines on some of
the older deepwater fields, as well as production downtime at several new
fields.

NATURAL GAS STORAGE

- ----------

(1) Combined injections and withdrawals volumes.

We collect fixed and variable fees for providing storage services, some of
which is generated from customers with cashout provisions, at a tariff-based
index calculation. We incur expenses as we maintain these volumetric imbalance
receivables and payables which are valued at current gas prices. For these
reasons, we believe that gross margin (storage revenues less storage expenses)
provides a more accurate and meaningful basis for analyzing operating results
for the natural gas storage segment. Cost of natural gas reflects the initial
loss of base gas in our storage facilities or the encroachment on our base gas
by third parties at the market price in the period of the loss or encroachment
and the monthly revaluation of these amounts based on the monthly change in
natural gas prices.

48

Second Quarter Ended June 30, 2003 Compared With Second Quarter Ended June 30,
2002

For the quarter ended June 30, 2003, margin was $5.7 million higher than
the same period in 2002 primarily due to an increase in subscribed firm storage
capacity attributable to the expansion of the Petal storage facility, which was
completed in June 2002.

Six Months Ended June 30, 2003 Compared With Six Months Ended June 30, 2002

For the six months ended June 30, 2003, margin was $11.5 million higher
than the same period in 2002 primarily due to an increase in subscribed firm
storage capacity attributable to the expansion of the Petal storage facility,
which was completed in June 2002, and our acquisition of the Wilson storage
facility lease in April 2002.

Operating expenses excluding, depreciation, depletion, and amortization for
the six months ended June 30, 2003 were $1.2 million higher than the same period
in 2002 primarily due to the acquisition of the Wilson storage facility lease in
April 2002.

PLATFORM SERVICES

Second Quarter Ended June 30, 2003 Compared With Second Quarter Ended June 30,
2002

For the quarter ended June 30, 2003, revenues from external customers were
$0.9 million higher than in the same period in 2002, of which $3.2 million is
attributable to the Falcon Nest fixed leg platform that went into operation in
March 2003. This increase is partially offset by lower revenues of $2.2 million
from East Cameron 373 resulting from lower demand fees and lower production.
Intersegment revenues were $2.4 million lower due to a decline in the fixed
portion of our platform access fees on the Viosca Knoll 817 and Garden Banks 72
platforms associated with contracts with one of our wholly owned subsidiaries,
which terms expired in June 2002 and December 2002. Operating expenses for the
same periods were $0.3 million lower due to lower operating and allocation
expense.

49

Six Months Ended June 30, 2003 Compared With Six Months Ended June 30, 2002

For the six months ended June 30, 2003, revenues from external customers
were $0.9 million higher than in the same period in 2002, of which $3.8 million
is attributable to the Falcon Nest fixed leg platform that went into operation
in March 2003. This increase is partially offset by lower revenues of $2.8
million from East Cameron 373 resulting from one time billing adjustments in
2002 for fixed monthly platform access fees, a gas dehydration fee, decreased
demand fees and lower production. Intersegment revenues were $4.8 million lower
due to a decline in the fixed portion of our platform access fees on the Viosca
Knoll 817 and Garden Banks 72 platforms associated with contracts with one of
our wholly owned subsidiaries, which terms expired in June 2002 and December
2002.

OTHER, NET

Second Quarter Ended June 30, 2003 Compared With Second Quarter Ended June 30,
2002

EBITDA related to non-segment activity for the quarter ended June 30, 2003,
was $0.8 million higher than the same period in 2002 due to lower platform
access fee expense as a result of the expiration in June 2002 of the fixed fee
portion of the Viosca Knoll 817 platform access fee contract and the Garden
Banks 72 platform access fee contract in December 2002. Partially offsetting
this increase was higher operating expenses associated with an increase in
professional services.

Six Months Ended June 30, 2003 Compared With Six Months Ended June 30, 2002

EBITDA related to non-segment activity for the six months ended June 30,
2003, was $4.0 million higher than in the same period in 2002 due to lower
platform access fee expense as a result of the expiration of the fixed fee
portion of the Viosca Knoll 817 platform access fee contract in June 2002 and
the Garden Banks 72 platform access fee contract in December 2002. Partially
offsetting this increase was higher operating expenses associated with an
increase in professional services.

DEPRECIATION, DEPLETION, AND AMORTIZATION

Depreciation, depletion, and amortization for the quarter and six months
ended June 30, 2003, was $6.7 million and $17.9 million higher than the same
periods in 2002. This increase is primarily due to our November 2002 acquisition
of the San Juan assets and our April 2002 acquisition of the EPN Holding assets.
Further contributing to the increase was the completion of the Falcon Nest
platform in March 2003 and the Petal expansion in June 2002.

INTEREST AND DEBT EXPENSE

Interest and debt expense, net of capitalized interest, for the quarter and
six months ended June 30, 2003, was approximately $10.3 million and $33.0
million higher than the same periods in 2002. This increase for the six month
period is primarily due to a higher weighted average interest rate, increase in
capitalized interest, a higher outstanding balance on our revolving credit
facility and increased interest incurred on the following indebtedness:

- the GulfTerra Holding term credit facility which we entered in connection
with our acquisition of the EPN Holding assets in April 2002;

- our $230 million 8 1/2% senior subordinated notes which we issued in May
2002 and used to repay a portion of the GulfTerra Holding term credit
facility;

- our $160 million senior secured term loan which we entered in October
2002;

- our $200 million 10 5/8% senior subordinated notes we issued and our
$237.5 million senior secured acquisition term loan we entered in
November 2002 in connection with our acquisition of the San Juan assets;
and

- our $300 million 8 1/2% senior subordinated notes which we issued in
March 2003 and used to repay our $237.5 million senior secured
acquisition term loan.

50

The increase in interest expense for the quarter ended June 30, 2003
compared to the same period in 2002 is attributable to the interest incurred on
the additional indebtedness discussed above, partially offset by lower weighted
average interest rates and lower outstanding balances on our revolving credit
facility and the GulfTerra Holding term credit facility and an increase in
capitalized interest.

Capitalized interest for the quarter and six months ended June 30, 2003 was
$2.6 million and $4.5 million, representing increases of $0.6 million and $0.9
million over the comparable prior periods. The increases are the result of an
increase in construction work-in-process as a result of increased expenditures
related to our construction projects.

LOSS DUE TO WRITE-OFF OF DEBT ISSUANCE COST

In March 2003, we repaid our $237.5 million senior secured term loan which
was due in May 2004 and recognized a loss of $3.8 million related to the
write-off of the unamortized debt issuance costs related to this loan.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Information, Note 7, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

See Item 1, Financial Information, Note 13, which is incorporated by
reference.

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 for the year ended December 31, 2002, and our
other filings with the Securities and Exchange Commission. 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

51

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 Securities and Exchange Commission.
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 for the year ended December 31, 2002, in addition to
information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices relating to gathering
activities in the San Juan Basin in anticipation of our acquisition of the San
Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby
we receive a fixed price of $3.525 per MMBtu and pay a floating price based on
the San Juan index. Beginning with the acquisition date in November 2002, we are
accounting for this derivative as a cash flow hedge under SFAS No. 133. In
February 2003, we entered into an additional derivative financial instrument to
continue to hedge our exposure during 2004 to changes in natural gas prices
relating to gathering activities in the San Juan Basin. The derivative is a
financial swap on 15,000 MMBtu per day whereby we receive a fixed price of $3.95
per MMBtu and pay a floating price based on the San Juan index. We are
accounting for this derivative as a cash flow hedge under SFAS No. 133. As of
June 30, 2003, the fair value of these cash flow hedges was a liability of $10.3
million. For the six months ended June 30, 2003, we reclassified a loss of $6.0
million from accumulated other comprehensive income resulting in a reduction to
earnings. 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. We estimate the entire amount will be classified from accumulated
other comprehensive income as a reduction to earnings over the next 18 months
and approximately $9.7 million will be reclassed as a reduction to earnings over
the next twelve months.

Prior to June 30, 2003, 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 2002 and 2003 to offset the risk of
increasing natural gas prices. As of June 30, 2003, these cash flow hedges
expired and we reclassified a gain of $0.2 million from accumulated other
comprehensive income to earnings. No ineffectiveness existed in this hedging
relationship because all purchase and sale prices were based on the same index
and volumes as the hedge transaction.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable portion of its LIBOR based interest rate on $75
million of its $185 million variable rate revolving credit facility at 3.49%
over the life of the swap. Prior to April 2003, under its credit facility,
Poseidon paid an additional 1.50% over the LIBOR rate resulting in an effective
interest rate of 4.99% on the hedged notional amount. Beginning in April 2003,
the additional interest Poseidon pays over LIBOR was reduced to 1.25% resulting
in an effective fixed interest rate of 4.74% on the hedged notional amount. As
of June 30, 2003, the fair value of its interest rate swap was a liability of
$0.9 million resulting in accumulated other comprehensive loss of $0.9 million.
We
52

included our 36 percent share of this liability of $0.3 million as a reduction
of our investment in Poseidon and as loss in accumulated other comprehensive
income which we estimate will be reclassified to earnings proportionately over
the next six months. Additionally, we have recognized in income our 36 percent
share of Poseidon's realized loss of $0.7 million for the six months ended June
30, 2003, or $0.2 million, through our earnings from unconsolidated affiliates.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on our fixed 8 1/2% $250 million senior subordinated
notes that were issued in May 2001. With this swap agreement, we will pay the
counterparty a LIBOR based interest rate plus a spread of 4.20% and receive a
fixed rate of 8 1/2%. We are accounting for this derivative as a fair value
hedge.

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 "significant deficiencies" or "material weaknesses" in
GulfTerra Energy Partners' Internal Controls, or whether GulfTerra Energy
Partners had identified any acts of fraud involving personnel who have a
significant role in GulfTerra Energy Partners' 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 our Board's Audit Committee and our independent
auditors and to report on

53

related matters in this section of the Quarterly Report. The principal executive
officer and principal financial officer note that there have not been any
significant changes in Internal Controls or in other factors that could
significantly affect Internal Controls, including any corrective actions with
regard to significant deficiencies and material weaknesses.

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 GulfTerra Energy Partners and its consolidated subsidiaries is made
known to 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.

54

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Financial Information, Note 7, which is incorporated herein by
reference.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

We have amended our partnership agreement, and issued a new series of
convertible units, both of which affect our common units. See Part I, Item 2,
Management's Discussion and Analysis, "General Partner Relationship" and
"Liquidity and Capital Resource" for discussions of how these changes affect our
common units, which is incorporated herein by reference.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

In May 2003, we announced that effective May 6, 2003, W. Matt Ralls, senior
vice president and chief financial officer of GlobalSantaFe Corporation, was
elected to join our board of directors.

Mr. Ralls, 54, is senior vice president and chief financial officer of
GlobalSantaFe, one of the largest international drilling contractors, providing
offshore and land drilling services to the world's leading oil and gas
companies. From 1997 to 2001, he was Global Marine's vice president, chief
financial officer and treasurer. Previously, he served as executive vice
president, chief financial officer and a director of Kelley Oil and Gas
Corporation and as vice president of Capital Markets and Corporate Development
for The Meridian Resource Corporation before joining Global Marine. He spent the
first 17 years of this career in commercial banking at the senior loan
management level. Mr. Ralls received an MBA from the University of Texas at
Austin.

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 May 16, 2003 to file exhibits
to the Registration Statement on Form S-3 (Registration No. 333-81772), relating
to the issuance of 1,118,881 Common Units and 80 Series F convertible units.

We filed a current report on Form 8-K dated June 6, 2003 to file exhibits
to the Registration Statement on Form S-3 (Registration No. 333-81772) relating
to our public offering of 1,150,000 Common Units (including the Underwriters'
over-allotment option to purchase 150,000 Common Units).

We filed a current report on Form 8-K dated July 1, 2003 to report the
pricing of our $250 million Senior Unsecured Notes.

We filed a current report on Form 8-K dated July 14, 2003 to announce the
completion of agreements to form a 50/50 joint venture with Valero Energy
Corporation in the Cameron Highway Oil Pipeline System project and to announce
the completion of a non-recourse financing for the project.

We also furnished information to the SEC on 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.

58

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.

By: GULFTERRA ENERGY COMPANY, L.L.C.,
its General Partner

Date: August 12, 2003 By: /s/ KEITH B. FORMAN
------------------------------------
Keith B. Forman
Vice President and Chief Financial
Officer
(Principal Financial Officer)

Date: August 12, 2003 By: /s/ KATHY A. WELCH
------------------------------------
Kathy A. Welch
Vice President and Controller
(Principal Accounting Officer)

59

INDEX TO EXHIBITS