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 SEPTEMBER 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

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 58,361,149 common units outstanding as of October 29,
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.

4

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. In connection
with our name change, we also changed the names of several subsidiaries in May
2003, including the following, as listed in the table below.

Our sole general partner is GulfTerra Energy Company, L.L.C., a
recently-formed Delaware limited liability company that is owned 90.1 percent by
a subsidiary of El Paso Corporation and 9.9 percent by Goldman, Sachs & Co.
(Goldman Sachs), a wholly owned subsidiary of Goldman Sachs Group Inc., a large
publicly-traded investment banking company. El Paso Corporation (through its
subsidiaries) owned 100 percent of our general partner until October 2003, when
Goldman Sachs acquired its interest in our general partner.

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 September 30, 2003, and for
the quarters and nine months ended September 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. Also, starting with the quarter ended June 30, 2002, we have
reflected the results of operations from our Prince assets disposition as
discontinued operations.

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. We review collectibility regularly and adjust the allowance as
necessary, primarily under the specific identification method. During 2003, we
increased our allowance by $2.0 million. As of September 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.

5

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 that constitute part of our non-segment assets.

Upon our adoption of SFAS No. 143, we recorded (i) a $7.4 million net
increase to property, plant, and equipment representing non-current retirement
assets, (ii) a $5.7 million increase to noncurrent liabilities representing
retirement obligations, and (iii) a $1.7 million increase to income as a
cumulative effect of accounting change. Each retirement asset is depreciated
over the remaining useful life of the long-term asset with which the retirement
liability is associated. An ongoing expense is recognized for the interest
component of the liability due to the changes in the value of the retirement
liability as a result of the passage of time, which we reflect as a component of
depreciation 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 lives of our assets or the
underlying reserves associated with our assets cannot be estimated. Therefore,
aside from the liability associated with the plugging 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 nine months ended September 30, 2003 and 2002, assuming the
provisions of SFAS No. 143 were adopted prior to the earliest period presented,
are shown below:

The pro forma amount of our asset retirement obligations at September 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:

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(1) Abandonment work performed during the quarter ended September 30, 2003.

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.

6

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.

Accounting for Derivative Instruments and Hedging Activities

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. This statement amends SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities to incorporate
several interpretations of the Derivatives Implementation Group (DIG), and also
makes several minor modifications to the definition of a derivative as it was
defined in SFAS No. 133. SFAS No. 149 is effective for contracts entered into or
modified after June 30, 2003. There was no initial financial statement impact of
adopting this standard, although the FASB and DIG continue to deliberate on the
application of the standard to certain derivative contracts, which may impact
our financial statements in the future.

Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity

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.

Accounting for Stock-Based Compensation

We use the intrinsic value method established in Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, to value
unit options issued to individuals who are on our general partner's current
board of directors and for those grants made prior to El Paso Corporation's
acquisition of our general partner in August 1998 under our Omnibus Plan and
Director Plan. For the quarters and nine months ending September 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.

7

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 and the effect of
the method used on reported results. This statement is effective for 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 individuals who
are on our general partner's current board of directors and for those grants
made prior to El Paso Corporation's acquisition of our general partner in August
1998 and will include data providing the pro forma income effect 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.

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 future amounts.

8

2. ACQUISITIONS AND DISPOSITIONS

San Juan Assets

During the quarter ended September 30, 2003, the total purchase price and
net assets acquired for our November 2002 acquisition of the San Juan assets
decreased $2.4 million due to post-closing purchase price adjustments related to
natural gas imbalances, NGL in-kind reserves and well loss reserves. 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.

EPN Holding Assets

During the nine months ended September 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.

9

Exchange with El Paso Corporation

In connection with our November 2002 San Juan assets acquisition, El Paso
Corporation retained the obligation to repurchase the Chaco Plant from us for
$77 million in October 2021. As part of El Paso Corporation's sale of 9.9
percent of our general partner, we released El Paso Corporation from that
obligation in exchange for El Paso Corporation contributing specified assets to
us. The communication assets we received will be used in the operation of our
pipeline systems. Prior to the October 2003 exchange, we had access to these
assets under our general and administrative services agreement with El Paso
Corporation. We recorded the received assets at El Paso Corporation's book value
of $23.3 million with the offset to partners' capital.

As a result of the October 2003 exchange, we changed our accounting
estimate of the depreciable life of the Chaco Plant, from 19 to 30 years in
order to depreciate the Chaco Plant over its estimated useful life as compared
to the original term of the repurchase agreement. Depreciation expense will
decrease approximately $0.5 million and $2.3 million on a quarter and annual
basis.

Cameron Highway Oil Pipeline Company

Refer to Note 10 for discussion related to our sale of a 50 percent
interest in Cameron Highway Oil Pipeline.

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 nine months ended September 30, 2003:

In October 2003 we declared a cash distribution of $0.71 per common unit
and Series C unit, $49.2 million in aggregate, for the quarter ended September
30, 2003, which we will pay on November 14, 2003, to holders of record as of
October 31, 2003. In addition, we will pay our general partner $21.2 million
related to its general partner interest. At the current distribution rate, our
general partner receives approximately 30.2 percent of the total cash
distributions for its role as our general partner.

Public offering of common units

Since January 1, 2003, we have issued the following common units in public
offerings:

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(1) Offering includes 80 Series F convertible units offered. Refer to
description below.

10

In addition to our public offerings of common units, in October 2003 we
sold 3,000,000 common units privately to Goldman Sachs in connection with their
purchase of a 9.9 percent membership interest in our general partner. We used
the net proceeds of $111.5 million from that private sale to partially fund the
redemption of all of our outstanding Series B preference units (see discussion
below related to the redemption of the Series B preference units). We used the
net proceeds of the remaining common unit offerings to temporarily reduce
amounts outstanding under our revolving credit facility and for general
partnership purposes.

In May 2003, we issued 1,118,881 common units and 80 Series F convertible
units in a registered offering to a large 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). The price at which the Series F convertible units could
have been converted to common units, assuming we had received a conversion
notice on September 30, 2003 and October 29, 2003, was $38.77 and $39.05. The
Series F convertible units may be converted into a maximum of 8,329,679 common
units. Holders of Series F convertible units are not entitled to vote or receive
distributions. The value associated with the Series F convertible units is
included in partners' capital as a component of common units capital.

In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26.00 per unit, paying the holder an amount of cash
equal to the market price of the net number of units. These amendments had no
effect on the classification of the Series F convertible units on the balance
sheet at September 30, 2003.

In connection with the offerings prior to October 2003, our general
partner, in lieu of a cash contribution, contributed to us approximately $2.0
million of our Series B preference units in order to maintain its one percent
general partner interest. We retired these preference units.

In October 2003, we redeemed all 123,865 of our remaining outstanding
Series B preference units for $156 million, a 7 percent discount from their
liquidation value of $167 million. For this redemption, we used the net proceeds
of $111.5 million from our sale of 3,000,000 common units to Goldman Sachs,
$44.1 million from cash on hand and from borrowings under our revolving credit
facility. We reflected the discount as an increase to the common units capital,
Series C units capital and to our general partner's capital accounts.

11

Other

Under our 1998 Omnibus Compensation Plan (Omnibus Plan), we granted, during
the nine months ended September 30, 2003, 17,500 unit options, 25,000
time-vested restricted units and 25,000 performance-based restricted units to
employees of El Paso Field Services, whose primary responsibilities are the
commercial management of our assets. Additionally, we granted 5,226 restricted
units and 10,500 unit options during the nine months ended September 30, 2003,
to non-employee directors of our Board of Directors under our 1998 Common Unit
Plan for Non-Employee Directors (formerly the 1998 Unit Option Plan for
Non-Employee Directors). We have accounted for all of these unit options and
restricted units, except for the unit options issued to non-employee directors,
in accordance with SFAS No. 123. Under SFAS No. 123, we report the fair value of
these issuances as deferred compensation. Deferred compensation is amortized to
compensation expense over the respective vesting or performance period. We have
accounted for the unit options issued to the non-employee directors of our
general partner's Board of Directors in accordance with APB No. 25.

We estimate the fair value of each unit option issued under the Omnibus
Plan during the nine months ended September 30, 2003, on the date of its grant
using the Black-Scholes option-pricing model, with the following weighted
average assumptions: dividend yield of 8.75%; expected volatility of 30.77%; a
risk-free interest rate of 3.31%; and an expected life of eight years. We will
amortize the fair value of the unit options over their two year vesting period.

We issued time-vested restricted units and the performance-based restricted
units at fair value at their date of grant. The restrictions on the time-vested
units will lapse in four years from the date of grant. The restrictions on the
performance-based restricted units will lapse if we achieve a specified level of
target performance for identified "greenfield" projects by June 1, 2007 (for the
15,000 performance-based restricted units issued in June 2003) and by August 1,
2007 (for the 10,000 performance-based restricted units issued in August 2003).
If we do not reach those targets by the applicable dates, the performance-based
units will be forfeited. We will amortize the fair value of the time-vested
restricted units over their four-year restricted period and the fair value of
the performance-based restricted units over their performance periods. The
performance-based restricted units are not entitled to vote or to receive
distributions, until after (and if) we achieve specified level of target
performance. The restricted units issued to non-employee directors of our
general partner's Board of Directors were issued at fair value at their date of
grant. 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 September 30, 2003, was
approximately $1.7 million. Deferred compensation is reflected as a reduction of
partners' capital and is allocated 1 percent to our general partner and 99
percent to our limited partners. Total fair value of options, time-vested
restricted units and performance based restricted units issued during the nine
months ended September 30, 2003 under both the Omnibus Plan and the Director
Plan was approximately $1.9 million.

Net proceeds from unit options exercised during the nine months ended
September 30, 2003, was approximately $7.6 million.

12

4. EARNINGS PER COMMON UNIT

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

13

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

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(1) Includes leasehold acquisition costs with an unamortized balance of $3.4
million at September 30, 2003. One interpretation being considered relative
to SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and
Intangible Assets is that oil and gas mineral rights held under lease and
other contractual arrangements representing the right to extract such
reserves for both undeveloped and developed leaseholds should be classified
separately from oil and gas properties, as intangible assets on our balance
sheets. We will continue to include these costs in property, plant, and
equipment until further guidance is provided.

6. FINANCING TRANSACTIONS

CREDIT FACILITIES

Revolving Credit Facility

In September 2003, we renewed our revolving credit facility to, among other
things, expand the credit available from $600 million to $700 million and extend
the maturity from May 2004 to September 2006.

Our credit facility consists of two parts: the revolving credit facility
and a $160 million senior secured term loan maturing in 2007. Our credit
facility is guaranteed by us and all of our subsidiaries, except for our
unrestricted subsidiaries, as detailed in Note 12, 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 our
credit facility is determined at our option using one of two indices that
include (i) a variable base rate (equal to the greater of the prime rate as
determined by JPMorgan Chase Bank, 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. This interest rate we are charged is contingent upon
our leverage ratio, as defined in our credit facility, and ratings we are
assigned by S&P or Moody's. The interest we are charged would increase by 0.25%
if the credit ratings on our senior secured credit facility decrease or our
leverage ratio decreases, or, alternatively, would decrease by 0.25% if these
ratings are increased or our leverage ratio improves. Additionally, we pay
commitment fees on the unused portion of our revolving credit facility at rates
that vary from 0.30% to 0.50%.

Our credit facility contains covenants that include restrictions on our and
our subsidiaries' ability to incur additional indebtedness or liens, sell
assets, make loans or investments, acquire or be acquired by other companies and
amend some of our contracts, as well as requiring maintenance of certain
financial ratios. Failure to comply with the provisions of any of these
covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries and restrict our ability to make
distributions to our unitholders.

14

At September 30, 2003, we had $328 million outstanding under our revolving
credit facility at an average interest rate of 5.0% as determined using the
variable base rate discussed above, increased by 0.50%. We decreased the average
interest rate under this facility to 3.13% in October 2003 when we elected to
convert the outstanding balances to LIBOR-based loans. The total amount
available to us at September 30, 2003, under this facility was $208 million. At
September 30, 2003, we had $157.5 million outstanding under our senior secured
term loan with an interest rate of 4.75%.

GulfTerra Holding Term Credit Facility

As part of our April 2002 EPN Holding assets acquisition, we entered into a
term credit facility to fund a portion of the purchase price. We repaid the $160
million balance of this term credit facility in July 2003 with proceeds from our
issuance of $250 million of 6 1/4% senior notes due 2010. We recognized a loss
of $1.2 million related to the write-off of unamortized debt issuance costs in
connection with our repayment of this facility.

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 this 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 in connection with our repayment of this
facility. 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%.

SENIOR NOTES

In July 2003, we issued $250 million in aggregate principal amount of
6 1/4% senior notes due June 2010. 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. 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
senior to all our existing and future subordinated debt and equally with all of
our existing and future senior debt, although they are effectively junior in
right of payment to all of our existing and future senior secured debt to the
extent of the collateral securing that 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 (1) 100 percent
of the principal amount plus accrued interest, or (2) the sum of the present
value of the remaining scheduled payments plus accrued interest.

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
facility 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 $293.5 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. 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. We may
redeem all or part of these notes at any time on or after June 1, 2007. The
redemption price on that date is 104.25 percent of the principal amount,
declining annually until it reaches 100 percent of the principal amount.

15

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480 million of our 8 1/2%
senior subordinated notes due 2011. 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 under SFAS No. 133. At September 30, 2003, the fair value of the swap was
a liability, included in non-current liabilities, of approximately $2.2 million.
The fair value of the hedged debt decreased by the same amount.

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
some (but not all) of our senior subordinated notes will be suspended should
they be similarly rated.

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 $123 million outstanding at
September 30, 2003. This credit agreement is secured by substantially all of
Poseidon's assets and includes restrictions on, among other things, its ability
to incur indebtedness, grant liens and make 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 leverage
ratio, as defined in its credit agreement. In April 2004, Poseidon's $185
million credit facility will mature; however, Poseidon is currently negotiating
with lenders to replace this facility.

In January 2002, Poseidon entered into a two-year swap agreement to hedge
the variable portion of its interest at 3.49% through January 2004 on $75
million of the $123 million outstanding. The effective interest rate on this
hedged amount is 4.74% (the variable LIBOR based rate locked in at 3.49% plus a
fixed margin of 1.25%) at September 30, 2003. As of September 30, 2003, the
variable LIBOR-based rate on the unhedged amount of $48 million was at an
interest rate of 2.38%.

Deepwater Gateway

At September 30, 2003, Deepwater Gateway, an unconsolidated affiliate in
which we have a 50 percent joint venture ownership interest, had $129 million
outstanding under its construction loan at an average interest rate of 2.93%.
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. This construction
loan is secured by substantially all of Deepwater Gateway's assets and includes
restrictions on, among other things, its ability to incur indebtedness, grant
liens and make distributions to its owners. Prior to conversion to the term
loan, Deepwater Gateway is prohibited from making distributions.

16

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, each of which fund
proportionately as construction costs are incurred.

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 principal
payments of $8.125 million, with the remaining unpaid principal amount payable
on the maturity date. If the construction loan fails to convert into a term loan
by December 31, 2006, the construction loan and senior secured notes become
fully due and payable. At September 30, 2003, Cameron Highway has $35 million
outstanding under the construction loan at an average interest rate of 4.18%.

The interest rate on Cameron Highway's senior secured notes is 3.25% over
the rate on 10-year U.S. Treasury securities. Principal payments of $4 million
are due quarterly from September 2008 through December 2011, $6 million each
from March 2012 through December 2012, and $5 million each from March 2013
through the principal maturity date of December 2013. At September 30, 2003,
Cameron Highway has $28 million outstanding under the notes at an average
interest rate of 7.31%.

Under the terms of its project loan facility, Cameron Highway must pay each
of the lenders and the senior secured noteholders commitment fees of 0.5% per
year on any unused portion of such lender's or noteholder's committed funds. The
project loan facility as a whole is secured by (1) substantially all of Cameron
Highway's assets, including, upon conversion, a debt service reserve capital
account, and (2) all of the equity interest in Cameron Highway. Other than the
pledge of our equity interest and our construction obligations under the
relevant producer agreements, 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 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 September 30, 2003 (in thousands):

2003........................................................ $ 2,500
2004........................................................ 5,000
2005........................................................ 5,000
2006........................................................ 333,000
2007........................................................ 140,000
Thereafter.................................................. 1,405,000
----------
Total long-term debt and other financing obligations,
including current maturities........................... $1,890,500
==========

17

7. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we, along with numerous other energy companies, were
named defendants in actions brought by Jack Grynberg on behalf of the U.S.
Government under the False Claims Act. Generally, these complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Native American lands, which
deprived the U.S. Government of royalties. The plaintiff in this case seeks
royalties that he contends the government should have received had the volume
and heating value 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, along with numerous other energy
companies, 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' motion to file another amended petition to narrow the proposed class
to royalty owners of wells in Kansas, Wyoming and Colorado 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 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 filed an appeal with the
Eighth Court of Appeals in El Paso, Texas. On August 15, 2003 the Court of
Appeals reversed the lower's courts calculation of past judgment interest but
otherwise affirmed the judgment. A motion for a rehearing was denied, a petition
for review by the Texas Supreme Court will be filed.

18

Also, GulfTerra Texas Pipeline L.P., (GulfTerra Texas, formerly known as
EPGT Texas Pipeline L.P.) now owned by GulfTerra Holding, was involved in
litigation with the City of Edinburg concerning the City's claim that GulfTerra
Texas was required to pay pipeline franchise fees under a contract the City had
with Rio Grande Valley Gas Company, which was previously owned by GulfTerra
Texas and is now owned by Southern Union Gas Company. An adverse judgment
against Southern Union and GulfTerra Texas was rendered in Hidalgo County State
District court in December 1998 and found a breach of contract, and held both
GulfTerra Texas and Southern Union jointly and severally liable to the City for
approximately $4.7 million. The judgment relied on the single business
enterprise doctrine to impose contractual obligations on GulfTerra Texas and
Southern Union's entities that were not parties to the contract with the City.
GulfTerra Texas appealed this case to the Texas Supreme Court seeking reversal
of the judgment rendered against GulfTerra Texas. The City sought a remand to
the trial court of its claim of tortious interference against GulfTerra Texas.
Briefs were filed and oral arguments were held in November 2002. In October
2003, the Texas Supreme Court issued an opinion in favor of GulfTerra Texas and
Southern Union on all issues.

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 September 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 occurring prior to our purchase of these
facilities.

Christopher Beverly and Gretchen Beverly, individually and on behalf of the
estate of John Beverly v. GulfTerra GC, L.P., et, al. In June 2003, the
plaintiffs sued us in state district court in Hardin County, Texas. The
plaintiffs are the parents of John Christopher Beverly, a two year old child who
died on April 15, 2002, allegedly as the result of his exposure to arsenic,
benzene and other harmful chemicals in the water supply. Plaintiffs allege that
several defendants are responsible for that contamination, including us and BP.
Our connection to the occurrences that are the basis for this suit appears to be
our August 2002 purchase of certain assets from BP, including a facility in
Hardin County, Texas known as the Silsbee compressor station. Under the terms of
the indemnity provisions in the Purchase and Sale Agreement between GulfTerra
and BP, GulfTerra requested that BP indemnify GulfTerra for any exposure. BP has
thus far declined assuming the indemnity obligation and we filed notice to
arbitrate BP's failure to indemnify us. Our costs and legal exposure related to
this lawsuit and claims are not currently determinable.

19

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

Environmental

Each of our operating segments is subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These laws and regulations are applicable to each segment and require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of September
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 to
have a material adverse effect on our financial position, results of operations
or cash flows. It is possible that new information or future developments could
require us to reassess our potential exposure related to environmental matters.
We may incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or relevant
developments occur, we will adjust our accrual amounts accordingly. While there
are still uncertainties relating to the ultimate costs we may incur, based upon
our evaluation and experience to date, we believe our current reserves are
adequate.

20

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 proposed by the NOPR are 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. In July 2003, FERC issued an order that
prospectively prohibits pipelines from negotiating rates based upon natural gas
commodity price indices and imposes certain new filing requirements to ensure
the transparency of negotiated rate transactions. Requests for rehearing were
filed on August 25, 2003 and remain pending. Even if the FERC denies the
rehearing requests, we do not expect that the final order would have a material
impact on us.

Cash Management Rule. On October 23, 2003, the FERC approved a final rule
in which it requires that a FERC regulated entity file its cash management
agreement with the FERC, maintain records of transactions involving its
participation in the cash management program, compute its proprietary capital
ratio quarterly based on criteria established by the FERC, and notify the FERC
45 days after the end of a calendar quarter whether its proprietary capital
ratio falls below 30 percent and subsequently when its proprietary capital ratio
returns to or exceeds 30 percent. In the final rule, FERC stated that the
requirements imposed by the rule are not in the nature of a regulation governing
participation in cash management programs and that the rule does not dictate the
content or terms for participating in a cash management program. Although the
order will be subject to rehearing, we do not think the final order will have a
material effect on us.

Under the rule, we believe that both HIOS and Petal will be able to
continue to participate in our cash management program. We are in the process of
reviewing and revising our cash management agreements pursuant to guidance
issued by the FERC in other interstate pipeline proceedings.

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.

21

Other Regulatory Matters. HIOS is subject to the jurisdiction of the FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. HIOS operates under a FERC approved tariff that governs its operations,
terms and conditions of service, and rates. We timely filed a required rate case
for HIOS on December 31, 2002. The rate filing and tariff changes are based on
HIOS' cost of service, which includes operating costs, a management fee and
changes to depreciation rates and negative salvage amortization. We requested
the rates be effective February 1, 2003, but the FERC suspended the rate
increase until July 1, 2003, subject to refund. As of July 1, 2003, HIOS
implemented the requested rates, subject to a refund, and has established a
reserve for its estimate of its refund obligation. We will continue to review
our expected refund obligation as the rate case moves through the hearing
process and may increase or decrease the amounts reserved for refund obligation
as our expectation changes. 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 unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast Region (and
these assets) in late September and early October of 2002. We are taking
numerous steps to determine the cause of the fuel differences, including a
review of receipt and delivery measurement data. As of September 30, 2003, we
had recorded fuel differences of approximately $9.4 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
will negatively impact our earnings.

In December 1999, GulfTerra Texas filed a petition with the FERC for
approval of its rates for interstate transportation service. In June 2002, the
FERC issued an order that required revisions to GulfTerra Texas' proposed
maximum rates. The changes ordered by the FERC involve reductions to rate of
return, depreciation rates and revisions to the proposed rate design, including
a requirement to separately state rates for gathering service. FERC also ordered
refunds to customers for the difference, if any, between the originally proposed
levels and the revised rates ordered by the FERC. We believe the amount of any
rate refund would be minimal since most transportation services are discounted
from the maximum rate. GulfTerra Texas has established a reserve for refunds. In
July 2002, GulfTerra Texas requested rehearing on certain issues raised by the
FERC's order, including the depreciation rates and the requirement to separately
state a gathering rate. GulfTerra Texas' request for rehearing 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.

22

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. The Railroad Commission has set their case for hearing beginning on
December 16, 2003.

While the outcome of all of our rates and regulatory matters cannot be
predicted with certainty, based on information known to date, we do not expect
the ultimate resolution of these matters to have a material adverse effect on
our financial position, results of operations or cash flows. As new information
becomes available or relevant developments occur, we will establish accruals as
appropriate.

Joint Ventures

We conduct a portion of our business through joint venture arrangements
(including our Cameron Highway, Deepwater Gateway and Poseidon joint ventures)
we form to construct, operate and finance the development of our onshore and
offshore midstream energy businesses. We are obligated to make our proportionate
share of additional capital contributions to our joint ventures only to the
extent that they are unable to satisfy their obligations from other sources
including proceeds from credit arrangements.

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. From August 2002 through our acquisition date, November 27,
2002, we accounted for this derivative under mark-to-market accounting since it
did not qualify for hedge accounting under SFAS No. 133. Through the acquisition
date in 2002, we recognized a $0.4 million net gain, ($1.0 million loss in the
third quarter of 2002 and $1.4 million gain in the fourth quarter of 2002) in
the margin of our natural gas pipelines and plants segment. 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 and August 2003, we entered into
additional derivative financial instruments to continue to hedge our exposure
during 2004 to changes in natural gas prices relating to gathering activities in
the San Juan Basin. The derivatives are financial swaps on 30,000 MMBtu per day
whereby we receive an average fixed price of $4.23 per MMBtu and pay a floating
price based on the San Juan index. We are accounting for all of our San Juan
gathering derivatives as cash flow hedges under SFAS No. 133. As of September
30, 2003, the fair value of these cash flow hedges was a liability of $2.4
million, as the market price at that date was higher than the hedge price of
$4.23. For the nine months ended September 30, 2003, we reclassified
approximately $8.4 million of unrealized accumulated loss related to these
derivatives from accumulated other comprehensive income as a decrease in
revenue. No ineffectiveness exists in this hedging relationship because all
purchase and sale prices are based on the same index and volumes as the hedge
transaction.

23

In connection with our GulfTerra Intrastate Alabama operations, we have
fixed price contracts with specific customers for the sale of predetermined
volumes of natural gas for delivery over established periods of time. We have
entered into cash flow hedges in 2002 and 2003 to offset the risk of increasing
natural gas prices for our purchases to satisfy these sales contracts. As of
September 30, 2003, the fair value of these cash flow hedges was a liability of
$11 thousand, as the market price at that date was lower than the hedge price of
$5.20. For the nine months ended September 30, 2003, we reclassified
approximately $223 thousand of unrealized accumulated gain related to these
derivatives from accumulated other comprehensive income to earnings as a
reduction of cost of natural gas. 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
September 30, 2003, the fair value of its interest rate swap was a liability of
$0.5 million, as the market interest rate was lower than the hedge rate of
4.99%, resulting in accumulated other comprehensive loss of $0.5 million. We
included our 36 percent share of this liability of $0.2 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 three months. Additionally, we have recognized as a reduction in income
our 36 percent share of Poseidon's realized loss of $1.3 million for the nine
months ended September 30, 2003, or $0.5 million, through our earnings from
unconsolidated affiliates.

We estimate the entire $3.0 million of unrealized losses included in
accumulated other comprehensive income at September 30, 2003, will be
reclassified from accumulated other comprehensive income as a reduction to
earnings over the next 15 months and approximately $2.9 million will be
reclassified as a reduction to earnings over the next twelve months. When our
derivative financial instruments are settled, the related amount in accumulated
other comprehensive income is recorded in the income statement in operating
revenues, cost of natural gas and other products, or interest and debt expense,
depending on the item being hedged. The effect of reclassifying these amounts to
the income statement line items is recording our earnings for the period at the
"hedged price" under the derivative financial instruments.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we 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 under SFAS No. 133. As of September 30, 2003, the fair value of the
interest rate swap was a liability included in non-current liabilities of
approximately $2.2 and the fair value of the hedged debt decreased by the same
amount.

The counterparties for our San Juan hedging activities are J. Aron and
Company, an affiliate of Goldman Sachs, and UBS Warburg. We do not require
collateral and do not anticipate non-performance by these counterparties.
Through June 2003, the counterparty for our GulfTerra Intrastate Alabama
operations was El Paso Merchant Energy. Beginning in August 2003, the
counterparty is UBS Warburg, and we do not require collateral or 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 interest rate swap on the 8 1/2% notes, and we do not
require collateral or anticipate non-performance by this counterparty.

24

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.

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
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 our 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.

We believe EBITDA is a useful measurement to our investors because it
allows them to evaluate the effectiveness of our business and operations and our
investments from an operational perspective, exclusive of the costs to finance
those activities, income taxes and depreciation and amortization, none of which
are directly relevant to the efficiency of those operations. This measurement
may not be comparable to measurements used by other companies and should not be
used as a substitute for net income or other performance measures.

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

- ----------

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

(2) Includes a $19 million gain recorded from the sale of our 50 percent
interest in Cameron Highway to Valero Energy Corporation in July 2003 (See
Note 10).

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:

NINE MONTHS ENDED SEPTEMBER 30, 2003
(IN THOUSANDS)

27

NINE MONTHS ENDED SEPTEMBER 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.

(2) Total earnings from unconsolidated affiliates includes a $882 thousand gain
associated with the sale of our interest in Copper Eagle.

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.

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 an additional sum 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, or $133 million, equity through capital contributions from the
Cameron Highway partners, which have already been made, 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.

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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 September 30,
2003 and 2002, were approximately 9 percent and 45 percent of our total revenue.
Revenues received from related parties for the nine months ended September 30,
2003 and 2002, were approximately 10 percent and 43 percent of our total
revenue. 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 replaced all our month-to-month arrangements that were previously with
Merchant Energy with similar arrangements with third parties.

29

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

At September 30, 2003, and December 31, 2002, our accounts receivable due
from related parties was $49.5 million and $83.8 million. At September 30, 2003
and December 31, 2002, our accounts payable due to related parties was $44.1
million and $86.1 million.

30

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:

31

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 we expect
to make a claim for approximately $5 million for cost incurred in the third
quarter and any additional costs which may be incurred in the fourth quarter of
2003, as costs exceeded the established thresholds during the third quarter of
2003.

We have also entered into capital contribution arrangements with entities
owned by El Paso Corporation, including its regulated pipelines, in the past,
and will most likely do so in the future, as part of our normal commercial
activities in the Gulf of Mexico. We have an agreement to receive $6.1 million,
of which $3.0 million has been collected, from ANR Pipeline Company for our
Phoenix project. As of September 30, 2003, we have received $10.5 million from
ANR Pipeline and $7.0 million from El Paso Field Services for the Marco Polo
natural gas pipeline. In October 2003, we collected $2 million from Tennessee
Gas Pipeline for our Medusa project. These amounts are reflected as a reduction
in project costs. Regulated pipelines often contribute capital toward the
construction costs of gathering facilities owned by others which are, or will
be, connected to their pipelines. El Paso Field Services' contribution is in
anticipation of additional natural gas volumes that will flow through to its
onshore natural gas processing facilities.

In August 2003, Arizona Gas Storage L.L.C., along with its 50 percent
partner APACS Holdings L.L.C., sold their interest in Copper Eagle Gas Storage
L.L.C. to El Paso Natural Gas Company (EPNG), a subsidiary of El Paso
Corporation. Copper Eagle Gas Storage is developing a natural gas storage
project located outside of Phoenix, Arizona. Arizona Gas Storage is an indirect
60 percent owned subsidiary of GulfTerra Energy Partners, L.P. and 40 percent
owned by IntraGas US, a Gaz de France North American subsidiary. APACS Holdings
L.L.C. is a wholly owned subsidiary of Pinnacle West Energy, a subsidiary of
Pinnacle West Capital Corporation. GulfTerra has the right to receive $6.2
million of the sale proceeds, including a note receivable for $4.9 million to be
paid quarterly over the next twelve months, from EPNG and recorded a gain of
$882 thousand related to the sale of Copper Eagle. In the event of EPNG default,
the Copper Eagle Gas Storage project will revert back to the original owners
without compensation to EPNG.

In September 2003, we entered into a nonbinding letter of intent with
Southern Natural Gas Company, a subsidiary of El Paso Corporation, regarding the
proposed development and sale of a natural gas storage cavern and the proposed
sale of an undivided interest in a pipeline and other facilities related to that
natural gas storage cavern. The new storage cavern would be located at our
storage complex near Hattiesburg, Mississippi. If Southern Natural Gas
determines that there is sufficient market interest, it would purchase the land
and mineral rights related to the proposed storage cavern and would pay our
costs to construct the storage cavern and related facilities. Upon completion of
the storage cavern, Southern Natural Gas would acquire an undivided interest in
our Petal pipeline connected to the storage cavern. We would also enter into an
arrangement with Southern Natural Gas under which we would operate the storage
cavern and pipeline on its behalf.

Before we consummate this transaction, and enter into definitive
transaction documents, the transaction must be recommended by the audit and
conflicts committee of our board of directors, which committee consists solely
of directors meeting the independent director requirements established by the
NYSE and the Sarbanes-Oxley Act and then approved by our general partner's full
board of directors.

In October 2003, we exchanged with El Paso Corporation its obligation to
repurchase the Chaco plant from us in 19 years for additional assets (refer to
Note 2). Also in October 2003, we redeemed all of our outstanding Series B
preference units (refer to Note 3).

32

The counterparty for one of our San Juan hedging activities is J. Aron and
Company, an affiliate of Goldman Sachs, the owner of a 9.9 percent membership
interest in our general partner. Goldman Sachs was also a co-manager of our
4,800,000 public common unit offering in October 2003, and is one of the lenders
under our revolving credit facility.

12. GUARANTOR FINANCIAL INFORMATION

As of September 30, 2003, our credit facility is 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.), and our general partner, and is collateralized by our general partner's
general and administrative services agreement and substantially all of our
assets. In addition, all of our senior notes and senior subordinated notes are
jointly, severally, fully and unconditionally guaranteed by us and all of our
subsidiaries, excluding our unrestricted subsidiaries. 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 nine months ended
September 30, 2003, consisted of our unrestricted subsidiaries. Non-guarantor
subsidiaries as of and for the quarters ended September 30, 2002 and June 30,
2002, consisted of our GulfTerra Holding (then known as EPN Holding)
subsidiaries, which owned the EPN Holding assets and equity interests in
GulfTerra Holding (then known as EPN 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.

33

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

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

34

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003

35

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002

36

CONDENSED CONSOLIDATING BALANCE SHEETS
SEPTEMBER 30, 2003

37

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2002

38

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003

39

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002

40

13. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51

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 have
neither sufficient equity at risk nor a controlling financial interest in the
entity. This standard requires a company to consolidate any VIE if it is
allocated a majority of the VIE's losses and/or returns, including fees paid by
the VIE.

The provisions of FIN No. 46 for all VIE's created after January 31, 2003,
was effective February 1, 2003. Our adoption of this standard for VIE's created
after January 31, 2003, did not have an effect on our financial position or
results of operations.

On October 9, 2003, the FASB issued FIN 46-6, Effective Date of FASB
Interpretation No. 46, Consolidation of Variable Interest Entities. The staff
position deferred the effective date for interests held by public entities in
variable interest entities or potential variable interest entities created
before February 1, 2003. The new effective date, for the variable interest
entities covered under FIN 46-6, is for the period ending after December 15,
2003. We continue to evaluate our joint venture and financing arrangements
created before February 1, 2003, to assess the impact, if any, of FIN No. 46 on
these arrangements.

41

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.

This quarter, we completed the sale of a 50 percent interest in Cameron
Highway Oil Pipeline to Valero Energy Corporation (Valero). Cameron Highway also
entered into its construction financing arrangements. We also improved the
partnership's financial flexibility by upsizing our revolving credit facility
from $600 million to $700 million and extended the maturity from May 2004 to
September 2006. Refer to "Liquidity and Capital Resources" below for further
discussion regarding the renewal of our revolving credit facility and Cameron
Highway financing agreement.

We continued to integrate our 2002 EPN Holding and San Juan acquisitions by
exchanging with El Paso Corporation in October 2003 its obligation to repurchase
the Chaco plant from us in 19 years for additional assets (refer to "Exchange
with El Paso Corporation" below for further discussion) related to our November
2002 San Juan assets acquisition. Also in October 2003, El Paso Corporation
completed the sale of 9.9 percent of our general partner to Goldman, Sachs & Co.
(Goldman Sachs) and we redeemed all of our outstanding Series B preference
units. The sale of the 9.9 percent interest in our general partner substantially
completed our 2003 corporate governance and independence goals. We also
completed a 4,800,000 common unit public offering in October 2003, achieving our
goal to reduce the partnership's debt to total capital ratio to a level below 60
percent.

INDUSTRY PERSPECTIVE

We believe the midstream sector is in a period of substantial and ongoing
change, which will provide significant growth opportunities for well-positioned
companies. We expect large and mid-size energy companies, including potentially
El Paso Corporation, to continue to divest midstream assets in an effort to
strengthen their balance sheets as well as to focus on core businesses. These
divestitures may produce attractive acquisition opportunities for us. In
addition, we believe the midstream sector is likely to experience substantial
consolidation through mergers and acquisitions. This consolidation may well
result in a few large, independent midstream businesses, a number of which we
believe will be MLPs, becoming the leading participants in this business sector.

GENERAL PARTNER RELATIONSHIP

Our corporate governance structure and independence initiatives

In October 2003, Goldman Sachs made a $200 million investment in us and our
general partner acquiring a 9.9 percent membership interest in our general
partner from El Paso Corporation for $88 million and 3,000,000 common units from
us for $112 million. Adding a co-owner of our general partner was one of the
major steps of our Independence Initiatives, which we identified as necessary
elements of functioning, and being evaluated by the capital markets, as a
stand-alone, independent operating company.

We have continued to improve our corporate governance model, which
currently meets the standards established by the Securities and Exchange
Commission (SEC) and New York Stock Exchange (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 October 2003,
we have already implemented the following initiatives:

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

42

- 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 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;

- completed a resource support agreement with El Paso Corporation;

- 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;

- 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 interest 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; and

- added Goldman Sachs as a co-owner of our general partner.

Additionally, as part of implementing our Independence Initiatives, we are
considering adding one more independent director to our board of directors. We
will continue to evaluate our Independence Initiatives and analyze whether
additional actions are desirable.

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 90.1 percent of our general partner. 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.

- is a significant stake-holder in us -- it owns approximately 19.0
percent, or 11,084,245, of our common units (decreased from 26.5 percent
as a result of our common unit offerings during the second and third
quarters of 2003 and decreased from 23.1 percent as a result of our
October 2003 offerings and its sale of 590,000 common units in October
2003), all 10,937,500 of our Series C units, which we issued in November
2002 for $350 million, and 90.1 percent of our general partner. 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 El Paso Corporation or its
subsidiaries. Under this registration statement, El Paso Corporation sold
590,000 of its common units in October 2003.

- 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.
43

As discussed above, we have implemented, and may further implement, 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 light of these Independence Initiatives or any other
arrangements, we may still be adversely affected if El Paso Corporation
continues to suffer financial stress.

Goldman Sachs' Investment in Our General Partner and Common Units

In connection with our Independence Initiatives, El Paso Corporation
decided to sell between 5 and 10 percent of its interest in our general partner
(which was then a wholly owned subsidiary of El Paso Corporation) and solicit
bids from interested investors. Goldman Sachs was the successful bidder and in
October 2003, Goldman Sachs acquired a 9.9 percent membership interest in our
general partner for $88 million. In connection with its investment in our
general partner, Goldman Sachs also purchased 3,000,000 common units from us for
$112 million. Our general partner's Audit and Conflicts Committee engaged an
independent financial advisor to provide a fairness opinion related to the sale
of our general partner interest. Based on this opinion, these transactions were
approved by the Audit and Conflicts Committee of our general partner's board of
directors and its full board of directors.

Through Goldman Sachs' membership interest in our general partner:

- it is entitled to receive 9.9 percent of all distributions made by our
general partner; and

- its consent is required before we or our general partner can liquidate,
dissolve or file a voluntary bankruptcy petition.

In connection with Goldman Sachs' investment, we entered into the following
agreements with El Paso Corporation and its affiliates and Goldman Sachs:

Exchange and Registration Rights Agreement. Under this agreement:

- Beginning in October 2008, Goldman Sachs will have the right to exchange
its 9.9 percent membership interest in our general partner for a number
of common units that would result in Goldman Sachs receiving quarterly
common unit distributions, based on the most recent cash distribution to
common unitholders, equal (subject to adjustments) to 9.9 percent of the
most recent cash distribution we have made to our general partner;

- The maximum number of common units that Goldman Sachs will be permitted
to receive in exchange for its entire membership interest in our general
partner may not exceed 9.9 percent of the sum of the total number of our
outstanding limited partner interests (calculated on a diluted basis)
plus the number of common units to be issued to Goldman Sachs in the
exchange. However, Goldman Sachs will not be permitted to receive a
number of common units at any point in time that, together with any other
common units owned by Goldman Sachs, would result in Goldman Sachs owning
more than 9.9 percent of our outstanding common units at that time.

- Goldman Sachs will have the right to effect the exchange prior to October
2008 upon the occurrence of specified events, including:

- the sale of all or substantially all of our or our general partner's
assets,

- our merger with another company,

- a change of control (as that term is defined in the Exchange and
Registration Rights Agreement) of the El Paso Corporation subsidiary
that owns 90.1 percent of our general partner,

- our liquidation,

- our distribution of cash from interim capital contributions (as
defined in our partnership agreement),

44

- in certain circumstances, the commencement of a voluntary or
involuntary bankruptcy proceeding against El Paso Corporation or any
of its material subsidiaries, or

- if we negotiate a reduction in the incentive distributions that we
pay to our general partner;

- Beginning in October 2010, or prior to October 2010 upon the occurrence
of certain events, we will have, and in certain instances El Paso
Corporation has, the right to cause Goldman Sachs to exchange its 9.9
percent membership interest in our general partner for common units;

- We have filed with the SEC, and have agreed to maintain the effectiveness
of, a shelf registration statement to register the 3,000,000 common units
we issued to Goldman Sachs as well as any common units Goldman Sachs
acquires in any exchange for its interest in our general partner; and

- Goldman Sachs agreed not to sell pursuant to the shelf registration
statement any of the 3,000,000 units it acquired from us for a minimum of
90 days, subject to certain exceptions (including upon a sale of common
units by us, El Paso Corporation or any of its subsidiaries before that
date).

Incentive Distribution Reduction Agreement. Under this agreement, if we
acquire Goldman Sachs' interest in our general partner under the Exchange and
Registration Rights Agreement, we will then return that interest to our general
partner in exchange for a reduction in our general partner's incentive
distribution payments based on the amount of the distributions attributable to
the membership interest exchanged.

Exchange With El Paso Corporation

In connection with our November 2002 San Juan assets acquisition, El Paso
Corporation retained the obligation to repurchase the Chaco plant from us for
$77 million in October 2021. As part of El Paso Corporation's sale of 9.9
percent of our general partner, we released El Paso Corporation from that
obligation in exchange for El Paso Corporation contributing specified assets to
us. The communications assets we received will be used in the operation of our
pipeline systems, furthering our independence strategy. Prior to the October
2003 exchange, we were paying a fee to El Paso Corporation for the use of their
assets. We recorded the received assets at El Paso Corporation's book value with
the offset to partners' capital. In connection with the exchange, El Paso
Corporation also agreed to provide us with the right to lease 80 percent of an
office building in San Antonio, Texas at no cost for 20 years.

As a result of the October 2003 exchange, we changed our accounting
estimate of the depreciable life of the Chaco Plant, from 19 to 30 years in
order to depreciate the Chaco Plant over its estimated useful life as compared
to the original term of the repurchase agreement. Depreciation expense will
decrease approximately $0.5 million and $2.3 million on a quarter and annual
basis.

Series B Preference Units

In October 2003, we redeemed all 123,865 of our remaining outstanding
Series B preference units for $156 million, a 7 percent discount from their
liquidation value of $167 million. For this redemption, we used the net proceeds
of $111.5 million from our sale of 3,000,000 common units to Goldman Sachs, and
$44.1 million from cash on hand and from borrowings under our revolving credit
facility. We reflected the discount as an increase to the common units capital,
Series C units capital and to our general partner capital accounts.

Fairness Opinion

In accordance with our procedures for evaluating and valuing material
transactions with El Paso Corporation, our general partner's Audit and Conflicts
Committee engaged an independent financial advisor to provide a fairness opinion
related to the transactions with Goldman Sachs, the asset exchange with El Paso
Corporation, and the redemption of Series B Preference Units. Based on this
opinion, our Audit and Conflicts Committee and the full Board approved these
transactions.

45

CAMERON HIGHWAY OIL PIPELINE COMPANY

In June 2003, we formed Cameron Highway Oil Pipeline Company and
contributed to it 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. 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.

In July 2003, we sold a 50 percent interest in Cameron Highway to Valero
for $86 million, forming a joint venture with Valero. Valero paid us
approximately $70 million at closing, including $51 million representing 50
percent of the capital investment expended through that date for the pipeline
project, and we recognized $19 million as a gain from the sale of long-lived
assets. In addition, Valero will pay us $5 million once the system is completed
and an additional $11 million by the end of 2006. We expect to reflect these
additional amounts as gains from the sale of long-lived assets in the periods
they are received.

The Cameron Highway oil pipeline system project is expected to be funded
with 29 percent, or $133 million, equity through capital contributions from the
Cameron Highway partners (currently, Valero and us), which have already been
made, 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. We and Valero are obligated to make additional capital
contributions to Cameron Highway if and to the extent that the construction
costs for the pipeline exceed Cameron Highway's capital resources, including the
initial equity contributions and proceeds from Cameron Highway's project loan
facility.

RELATED PARTY TRANSACTIONS

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

For the quarter ended September 30, 2003, $8.4 million of our related party
revenue came from Merchant Energy for natural gas transportation and storage
agreements. In November 2002, El Paso Corporation announced its intention to
exit the energy trading business. Currently, we have a $5.1 million letter of
credit from Merchant Energy representing two months of transportation revenues.
During the quarter ended September 30, 2003, Merchant Energy continued to fully
utilize these agreements. As of June 30, 2003, we replaced all our
month-to-month, market priced sales of natural gas to Merchant Energy with
similar arrangements with third parties. In October 2003, Merchant Energy
transferred the natural gas transportation and storage agreements they have with
us to El Paso Field Services.

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.

The fees we incur for services under our general and administrative
services agreement with El Paso Corporation reflect the benefit from El Paso
Corporation's ability to utilize their economies of scale to negotiate service
levels at favorable costs. During 2002, these fees increased as a result of the
acquisitions of the EPN Holding and San Juan assets. We expect the management
fee will continue to be adjusted to reflect increases in services provided. We
anticipate we will continue to obtain these services from El Paso Corporation;
however, if these services were to end, our expenditures may increase as we may
not be able to obtain the same level of services at comparable costs.

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

46

LIQUIDITY AND CAPITAL RESOURCES

Our principal requirements for cash, other than our routine operating
costs, are for capital expenditures, debt service, business acquisitions and
distributions to our partners. We plan to fund our short-term cash needs,
including operating costs, maintenance capital expenditures and cash
distributions to our partners, from cash generated from our operating activities
and borrowings under our credit facility. Capital expenditures we expect to
benefit us over longer time periods, including our organic growth projects and
business acquisitions, we plan to fund through a variety of sources (either
separately or in combination), which include issuing additional common units,
borrowing under commercial bank credit facilities, issuing public or private
placement debt and other financing transactions. We plan to fund our debt
service requirements through a combination of refinancing arrangements and cash
generated from our operating activities.

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

COMMON UNITS

Our announced strategy for 2003 is to continue to finance or re-finance our
growth with 50 percent equity to ensure a sound capital structure. Since January
2003, we have raised net proceeds of approximately $387.5 million through public
offerings of 11,026,109 common units, successfully accomplishing part of our
strategy for 2003. We used the net proceeds from our public offerings of common
units to temporarily reduce amounts outstanding under our revolving credit
facility and for general partnership purposes. The following table provides
additional detail regarding our public offerings since January 2003:

In addition to our public offerings of common units, in October 2003 we
sold 3,000,000 common units privately to Goldman Sachs in connection with their
purchase of a 9.9 percent membership interest in our general partner. We used
the net proceeds of $111.5 million from that private sale to partially fund the
redemption of all of our outstanding Series B preference units.

We expect to use the proceeds we receive from any additional capital we
raise through the issuance of additional common units to temporarily reduce
amounts outstanding under our credit facility, 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.

47

SERIES B PREFERENCE UNITS

In connection with our 2003 public offerings of common units through
September 30, 2003, our general partner, in lieu of a cash contribution,
contributed to us, and we retired, 1,527 Series B preference units with
liquidation value of approximately $2.0 million, including accrued distributions
of approximately $0.5 million, to maintain its one percent general partner
interest. In October 2003, we redeemed all of our remaining outstanding Series B
preference units. Refer to previous discussion "Series B Preference Units", for
further discussion.

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 average closing price of our
common units for the last seven days of the 60 day period included in (i). The
price at which the Series F convertible units could have been converted to
common units assuming we had received a conversion notice on September 30 and
October 29, 2003, was $38.77 and $39.05. The Series F units may be converted
into a maximum of 8,329,679 common units. Holders of Series F convertible units
are not entitled to vote or receive distributions. The value associated with the
Series F convertible units is included in partners' capital as a component of
common units capital.

In August 2003, we amended the terms of the Series F convertible units to
permit the holder to elect a "cashless" exercise -- that is, an exercise where
the holder gives up common units with a value equal to the exercise price rather
than paying the exercise price in cash. If the holder so elects, we have the
option to settle the net position by issuing common units or, if the settlement
price per unit is above $26.00 per unit, paying the holder an amount of cash
equal to the market price of the net number of units. These amendments had no
effect on the classification of the Series F convertible units on the balance
sheet at September 30, 2003.

INDEBTEDNESS AND OTHER OBLIGATIONS

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes due 2010. We used the proceeds of approximately
$293.5 million, net of issuance costs, to repay all indebtedness outstanding
under our $237.5 million senior secured acquisition term loan and to temporarily
repay $55.5 million of the balance outstanding under our revolving credit
facility.

In July 2003, we issued $250 million in aggregate principal amount of
6 1/4% senior notes due 2010. We used the proceeds of approximately $245.1
million, net of issuance costs, to repay the remaining $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.

48

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. At September 30,
2003, Cameron Highway had $35 million outstanding under the construction loan
and $28 million of senior secured notes outstanding.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we 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 under SFAS No. 133. At September 30, 2003, the fair value of the swap was
a liability, included in non-current liabilities, of approximately $2.2 million.
The fair value of the hedged debt decreased by the same amount.

In September 2003, we renewed our credit facility to among other things,
increase the commitment level under the revolving component from $600 million to
$700 million and extend the maturity from May 2004 to September 2006. Under the
terms of our renewed credit facility, the interest rate we are charged is
contingent upon our leverage ratio, as defined in our credit facility, and
ratings we are assigned by S&P or Moody's. The interest we are charged would
increase by 0.25% if the credit ratings on our senior secured credit facility
decrease or our leverage ratio decreases, or alternatively, would decrease by
0.25% if these ratings are increased or our leverage ratio improves.
Additionally, we pay commitment fees on the unused portion of our revolving
credit facility at rates that vary from 0.30% to 0.50%. These increases in our
credit facility costs are the only additional costs we would bear in direct
relationship to our financing contracts.

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 September 30, 2003, that we
believe could affect our liquidity (in millions):

49

CAPITAL EXPENDITURES

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
September 30, June 30 and March 31, 2003 as presented in our 2002 Annual Report
on Form 10-K, were $78, $92 and $120 million; however, our actual expenditures
were approximately $39, $125 and $80 million.

The table below depicts our estimate of projects and capital maintenance
expenditures through September 30, 2004. These expenditures are net of project
financings and anticipated contributions in aid of construction and
contributions from joint venture partners. We expect to be able to fund these
forecasted expenditures from the combination of operating cash flow and funds
available under our revolving credit facility and other financing arrangements.
Actual results may vary from these projections.

CONSTRUCTION PROJECTS

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

(1) Includes 100 percent of costs and is not reduced for anticipated
contributions in aid of construction, project financings and contributions
from joint venture partners. We expect to receive $6.1 million of which $3.0
million has been collected from ANR Pipeline Company for our Phoenix
project. We have received $10.5 million from ANR Pipeline Company and $7.0
million from El Paso Field Services for the Marco Polo natural gas pipeline.
In October 2003, we collected $2 million from Tennessee Gas Pipeline for our
Medusa project.

(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 sold a 50 percent interest in Cameron Highway to Valero
Energy Corporation. Valero paid us approximately $51 million at closing
representing 50 percent of the capital investment expended through that
date.

50

PROJECTS ANNOUNCED IN 2003

Front Runner Downstream Oil Pipeline Project. In September 2003, we
announced that Poseidon, our 36 percent owned joint venture, entered into an
agreement for the purchase and sale of crude oil from the Front Runner Field.
Poseidon will construct, own and operate the $28 million project, which will
connect the Front Runner Field with Poseidon's existing system at Ship Shoal
Block 332. The new 36-mile, 14-inch pipeline is expected to be operational by
the middle of 2004 and have a capacity of 65,000 barrels per day. As Poseidon
expects to fund Front Runner's capital expenditures from its operating cash flow
and from its revolving credit facility, we do not expect to receive
distributions from Poseidon until the Front Runner pipeline is completed.

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 September
30, 2003, we have spent approximately $1.5 million related to this project.

Petal Expansion Project. In September 2003, we entered into a nonbinding
letter of intent with Southern Natural Gas Company, a subsidiary of El Paso
Corporation, regarding the proposed development and sale of a natural gas
storage cavern and the proposed sale of an undivided interest in a pipeline and
other facilities related to that natural gas storage cavern. The new storage
cavern would be located at our storage complex near Hattiesburg, Mississippi. If
Southern Natural Gas determines that there is sufficient market interest, it
would purchase the land and mineral rights related to the proposed storage
cavern and would pay our costs to construct the storage cavern and related
facilities. Upon completion of the storage cavern, Southern Natural Gas would
acquire an undivided interest in our Petal pipeline connected to the storage
cavern. We would also enter into an arrangement with Southern Natural Gas under
which we would operate the storage cavern and pipeline on its behalf.

Before we consummate this transaction, and enter into definitive
transaction documents, the transaction must be recommended by the audit and
conflicts committee of our general partner's board of directors, which committee
consists solely of directors meeting the independent director requirements
established by the NYSE and the Sarbanes-Oxley Act and then approved by our
general partner's full board of directors.

51

ACQUISITIONS

San Juan Assets

During the quarter ended September 30, 2003, the total purchase price and
net assets acquired for our November 2002 acquisition of the San Juan assets
decreased $2.4 million due to post-closing purchase price adjustments related to
natural gas imbalances, NGL in-kind reserves and well loss reserves. 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.

EPN Holding

During the nine months ended September 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.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $209.4 million for the nine
months ended September 30, 2003, compared to $138.5 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.

52

CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities was approximately $201.4 million for
the nine months ended September 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 offset
in part by $69.8 million in proceeds from the sale of a 50 percent interest in
Cameron Highway to Valero, $1.3 million in proceeds from the sale of our
interest in Copper Eagle and $7.6 million from the sale and retirement of other
assets.

CASH FROM FINANCING ACTIVITIES

Net cash provided by financing activities was approximately $14.9 million
for the nine months ended September 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.

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 owner of 90.9 percent
of our general partner. As a result of these 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 nine 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 September 30, 2003 and December
31, 2002, our allowance was $4.5 million and $2.5 million.

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.

53

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.

CONSOLIDATED RESULTS

We reported third quarter 2003 net income of $60.2 million ($0.62 per
unit), up 152 percent from $23.8 million ($0.21 per unit) from third quarter
2002. Earnings before interest, taxes, depreciation, and amortization (EBITDA)
increased 78 percent to $122.8 million in the third quarter 2003 compared with
$68.9 million in the third quarter of 2002.

For the nine months ended September 30, 2003, net income was $151.7 million
($1.56 per unit), a 112-percent increase as compared to $71.7 million ($0.72 per
unit) for the same nine months ended 2002. EBITDA for the nine months ended
September 30, 2003 was $337.4 million, an increase of 79 percent from the $188.4
million reported for the same period of 2002.

We use 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 our 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:

54

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 nine months
ended September 30, 2003, was $516 thousand and $1,771 thousand.

55

We provide natural gas gathering and transportation services for a fee.
However, 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 price paid to the producers.
Accordingly, under these agreements, our operating revenues and costs of natural
gas and other products are impacted by changes in energy commodity prices,
however, our margin for these agreements reflects only the fee we received for
gathering services. At our Indian Basin processing facility, our revenues
reflect the gross sales of natural gas liquids we retain as a processing fee and
the natural gas liquids purchased from other producers under the marketing
provisions of their contracts. Included in our cost of natural gas and other
products is the payment to the producers for the natural gas liquids we marketed
on their behalf. For these reasons, we feel that gross margin (revenue less cost
of natural gas and other products) provides a more accurate and meaningful basis
for analyzing operating results for this segment. Revenues at our Chaco
processing facility are representative of our processing fee since the natural
gas liquids purchased from the producers at this facility is minimal.

During the latter half of 2002, we experienced a significant unfavorable
variance between the fuel usage on HIOS and the fuel collected from our
customers for our use. We believe a series of events may have contributed to
this variance, including two major storms that hit the Gulf Coast Region (and
these assets) in late September and early October of 2002. We are taking
numerous steps to determine the cause of the fuel differences, including a
review of receipt and delivery measurement data. As of September 30, 2003, we
had recorded fuel differences of approximately $9.4 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
will negatively impact the future results of our natural gas pipelines and
plants segment.

Third Quarter Ended September 30, 2003 Compared With Third Quarter Ended
September 30, 2002

Natural gas pipelines and plants margin for the quarter ended September 30,
2003, was $47.7 million higher than in the same period in 2002. Our San Juan
Basin assets, acquired in November 2002, accounted for approximately $44.8
million of the increase. Margin also increased by approximately $2.0 million due
to an increase in volumes attributable to 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 approximately $1.3 million due to higher NGL prices in 2003, which favorably
impacted margins at our Indian Basin processing facility. Partially offsetting
these increases was a decrease in volumes on our HIOS pipeline due to naturally
declining production in the western regions of the Gulf of Mexico.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter ended September 30, 2003, were $12.2 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 $6.6 million due to higher repair and maintenance expenses of $1.9
million on our Texas intrastate pipeline, which were unusually low in 2002 due
to timing of expenditures, and $1.3 million attributable to repairs on our
Medusa gas pipeline, which was damaged by an anchor after construction.
Additionally, operating expenses were higher by $3.1 million due to an increase
associated with our general and administrative services agreement with
subsidiaries of El Paso Corporation, as a result of our acquisitions in 2002.

Other income for the quarter ended September 30, 2003, primarily relates to
earnings from our unconsolidated affiliate, Coyote Gas Treating, LLC, which we
acquired in connection with the San Juan asset acquisition in November 2002.

The noncash hedge loss for the quarter ended September 30, 2002, is related
to our San Juan hedging activity prior to our acquisition of the San Juan assets
in November 2002. Prior to this acquisition we accounted for our San Juan
hedging activity under mark-to-market accounting since it did not qualify for
hedge accounting under SFAS No. 133.

56

Nine Months Ended September 30, 2003 Compared With Nine Months Ended September
30, 2002

Natural gas pipelines and plants margin for the nine months ended September
30, 2003, was $172.3 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 $130.0 million and $36.7
million of the increase. Margin also increased by $6.0 million due to an
increase in volumes attributable to 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 $3.0
million due to higher NGL prices in 2003, which favorably impacted margins at
our Indian Basin processing facility. Partially offsetting these increases was a
$1.0 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, offset by an
increase in base business performance. The increases were also offset by an
additional $2.9 million decrease in margin related to lower volumes on our HIOS
pipeline due to natural decline in the western region of the Gulf of Mexico.

Operating expenses excluding depreciation, depletion, and amortization for
the nine months ended September 30, 2003, were $49.8 million higher than the
same period in 2002 primarily due to the acquisition of the San Juan Basin and
EPN Holding assets. Excluding the operating costs of these acquired assets,
operating expenses increased by $21.4 million due to increased operating
expenses of $13.3 million associated with our general and administrative
services agreement with subsidiaries of El Paso Corporation. The increase in
operating expenses is also attributable to an increase in our allowance for
doubtful accounts of $2.0 million, higher repair and maintenance expenses of
$6.3 million, of which $5.0 million relates to expenditures on our Texas
intrastate pipeline, which were unusually low in 2002 due to timing of
expenditures, and $1.3 million attributable to repairs on our Medusa gas
pipeline, which was damaged by an anchor after construction.

Other income for the nine months ended September 30, 2003, primarily
relates to earnings from our unconsolidated affiliate, Coyote Gas Treating, LLC,
which we acquired in connection with the San Juan asset acquisition in November
2002.

The noncash hedge loss for the nine months ended September 30, 2002, is
related to our San Juan hedging activity prior to our acquisition of the San
Juan assets in November 2002. Prior to this acquisition we accounted for our San
Juan hedging activity under mark-to-market accounting since it did not qualify
for hedge accounting under SFAS No. 133.

57

OIL AND NGL LOGISTICS

- ----------

(1) Earnings from unconsolidated affiliates for the quarter and nine months
ended September 30, 2003, was $1,797 thousand and $6,845 thousand. Earnings
from unconsolidated affiliates for the quarter and nine months ended
September 30, 2002, was $3,168 thousand and $10,541 thousand.

(2) Represents 100 percent of the volumes flowing through the pipeline, in which
we own a 36 percent joint venture interest.

(3) Represents a gain of $19 million associated with the sale of our 50 percent
interest in Cameron Highway to Valero Energy Corporation in July 2003. Refer
to previous discussion regarding "Cameron Highway Oil Pipeline Company."

The majority of the earnings from the oil and NGL logistics segment are
generated from volume-based fees for providing transportation of oil and NGL and
fractionation of NGL. However, many of the agreements with the customers on our
oil pipelines require that we purchase oil from the customer at the inlet of our
pipeline for an index price, less an amount that compensates us for
transportation services, and resell the oil to the customer at the outlet of our
pipeline at the same index price. Although the effect of these transactions is
that we receive a volume-based fee for our services, our operating revenue and
cost of natural gas and other products include the index price that we pay and
receive. For these reasons, we believe that gross margin (revenue less cost of
natural gas and other products) provides a more accurate and meaningful basis
for analyzing operating results for this segment.

Gross margin is driven by product pricing for both oil and NGL and volumes.
Both oil and NGL volumes are impacted by natural resource decline as well as
increases in new production. Volumes at our Texas NGL fractionation facilities
are significantly impacted by processing economics, which are driven by the
difference between natural gas prices and NGL prices. In 2003, natural gas
prices have been high relative to NGL prices resulting in poor processing
economics that reduce the amount of NGL extracted from natural gas and available
for fractionation. We expect these economics to continue into next year.

58

Third Quarter Ended September 30, 2003 Compared With Third Quarter Ended
September 30, 2002

For the quarter ended September 30, 2003, margin was $3.3 million higher
than the same period in 2002. Our Texas NGL systems and our Typhoon Oil
Pipeline, both acquired in November 2002, contributed approximately $5.5 million
to the increase. Partially offsetting this increase was a $1.7 million decline
in margin for our Texas NGL fractionation assets due to lower volumes resulting
from poor processing economics.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter ended September 30, 2003, were $5.0 million higher than the same
period in 2002 primarily due to increased operating expenses related to our
November 2002 acquisition of the Typhoon Oil Pipeline and the Texas NGL systems.

Other income for the quarter ended September 30, 2003, was $1.4 million
lower than the same period in 2002 due to a decrease in cash distributions from
our unconsolidated affiliate Poseidon. Poseidon experienced lower earnings due
to reduced volumes, primarily attributable to natural production declines on
some of the older deepwater fields to which it connects, as well as production
downtime at several new fields.

Nine Months Ended September 30, 2003 Compared With Nine Months Ended September
30, 2002

For the nine months ended September 30, 2003, margin was $12.6 million
higher than the same period in 2002. Our acquisition, in November 2002, of the
Texas NGL systems and Typhoon Oil Pipeline contributed approximately $16.6
million to the increase. Partially offsetting this increase was a $3.6 million
decrease for our Texas NGL fractionation assets due to lower volumes resulting
from poor processing economics.

Operating expenses excluding depreciation, depletion, and amortization for
the nine months ended September 30, 2003 were $9.9 million higher than the same
period in 2002, primarily due to increased operating expenses related to our
November 2002 acquisition of the Typhoon Oil Pipeline and the Texas NGL systems.

Other income for the nine months ended September 30, 2003, was $3.7 million
lower than the same period in 2002 due to a decrease in cash distributions from
our unconsolidated affiliate Poseidon. Poseidon experienced lower earnings due
to natural production declines on some of the older deepwater fields, as well as
production downtime at several new fields.

59

NATURAL GAS STORAGE

- ----------

(1) Cash distributions from unconsolidated affiliates, in excess of (less than)
earnings is related to the sale of our interest in Copper Eagle to El Paso
Natural Gas Company.

(2) Combined injections and withdrawals volumes.

At our Petal and Hattiesburg storage facilities, we collect fixed and
variable fees for providing storage services, some of which is generated from
customers with cashout provisions, calculated by reference to a tariff-based
index. We incur expenses, which are reflected as cost of natural gas, as we
maintain these volumetric imbalance receivables and payables, all of which are
valued at current gas prices. For these reasons, we believe that gross margin
(revenue less cost of natural gas and other products) provides a more accurate
and meaningful basis for analyzing operating results for this segment. 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.

Third Quarter Ended September 30, 2003 Compared with Third Quarter Ended
September 30, 2002

For the quarter ended September 30, 2003, margin was $2.0 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.
Although the expansion was completed in June 2002, we did not receive 100
percent of expected demand payments until September 2002, when the last pipeline
interconnect was placed in service.

Nine Months Ended September 30, 2003 Compared with Nine Months Ended September
30, 2002

For the nine months ended September 30, 2003, margin was $13.5 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. In addition, margin attributable to Wilson
storage was up an additional $0.9 million due to new contracts, offset by a $1.1
million decline in firm contracts at our Hattiesburg storage facility.

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Operating expenses excluding, depreciation, depletion, and amortization for
the nine months ended September 30, 2003 were $1.1 million higher than the same
period in 2002 primarily due to our acquisition of the Wilson storage facility
lease in April 2002 and expansion of the Petal storage facility in June 2003.
Operating costs of our original storage facilities have remained fairly
consistent.

PLATFORM SERVICES

Our platform services segment generally receives revenue through demand
fees (regular payments made by customers using our platform services regardless
of volumes) and commodity charges (volume-based payments made by customers).
Contracts for platform services often include both demand charges and commodity
charges, but demand charges generally expire after a fixed period of time.

Third Quarter Ended September 30, 2003 Compared with Third Quarter Ended
September 30, 2002

For the quarter ended September 30, 2003, revenues were $1.6 million higher
than in the same period in 2002, of which $3.1 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 $1.5 million from East Cameron
373 resulting from lower demand fees. Intersegment revenues were $0.9 million
lower due to a decline in demand fees on the Garden Banks 72 platform associated
with contracts with one of our wholly owned subsidiaries, which terms expired in
December 2002.

61

Nine Months Ended September 30, 2003 Compared with Nine Months Ended September
30, 2002

For the nine months ended September 30, 2003, revenues from external
customers were $2.4 million higher than in the same period in 2002, of which
$6.9 million is attributable to the Falcon Nest fixed leg platform that went
into operation in March 2003. Partially offsetting this increase are lower
revenues of $4.1 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 $5.6
million lower due to a decline in demand 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

EBITDA related to non-segment activity for the quarter and nine months
ended September 30, 2003, was $0.4 and $4.4 million higher than the same periods
in 2002 primarily due to lower demand fee expense as a result of the expiration
of the fixed fee portion of the Viosca Knoll 817 contract in June 2002 and the
Garden Banks 72 contract in December 2002 and higher oil and natural gas prices
in 2003. Partially offsetting these increases were lower production from the
Garden Banks 117 and Viosca Knoll 817 fields and higher operating expenses
associated with an increase in professional fees, including legal, accounting
and consulting services.

In connection with the sale 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.
These payments from El Paso Corporation have been reflected in EBITDA related to
non-segment activities and will terminate in the first quarter of 2004.

DEPRECIATION, DEPLETION, AND AMORTIZATION

Depreciation, depletion, and amortization for the quarter and nine months
ended September 30, 2003, was $5.9 million and $23.8 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. We have
several capital projects in process, and as additional assets from our completed
projects are placed into service, depreciation, depletion and amortization
expense will increase. The amount of additional expense will be a function of
the final cost of each project and each project's expected useful life.

INTEREST AND DEBT EXPENSE

Interest and debt expense, net of capitalized interest, for the quarter and
nine months ended September 30, 2003, was approximately $11.1 million and $44.2
million higher than the same periods in 2002. The increase for the nine month
period is primarily due to a higher weighted average interest rate (4.0%
compared to 3.65% for the nine months ended September 30, 2002) on our revolving
credit facility and interest incurred on the following indebtedness:

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

- our $160 million senior secured term loan, borrowed in October 2002;

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

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

- our $250 million 6 1/4% senior notes, issued in July 2003 and used to
repay our GulfTerra Holding term credit facility and temporarily reduce
indebtedness outstanding under our revolving credit facility.

62

The increase in our interest expense for the nine months ended September
30, 2003 was partially offset by lower average balances outstanding under our
revolving credit facility and the GulfTerra Holding term credit facility during
2003 due to repayments from net proceeds of our 2003 debt and equity offerings.

The increase in interest expense for the quarter ended September 30, 2003
compared to the same period in 2002 is attributable to the interest incurred on
the additional indebtedness discussed above, excluding our $230 million 8 1/2%
senior subordinated notes issued in May 2002, partially offset by lower weighted
average interest rates and lower outstanding balances on our revolving credit
facility and the GulfTerra Holding term credit facility, which we repaid in July
2003.

Capitalized interest for the quarter and nine months ended September 30,
2003 was $2.5 million and $7.0 million, representing increases of $1.7 million
and $2.6 million over the comparable prior periods. The increases are the result
of an increase in average construction work-in-process in 2003 as a result of
our construction projects.

LOSSES DUE TO WRITE-OFF OF DEBT ISSUANCE COSTS

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.

In July 2003, we repaid our $160 million GTM Holding term credit facility
that was scheduled to mature in April 2005 and recognized a loss of $1.2 million
related to the write-off of the unamortized debt issuance costs associated with
this facility.

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;

63

- 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 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. From August 2002 through our acquisition date, November 27,
2002, we accounted for this derivative under mark-to-market accounting since it
did not qualify for hedge accounting under SFAS No. 133. Through the acquisition
date in 2002, we recognized a $0.4 million net gain, ($1.0 million loss in the
third quarter of 2002 and $1.4 million gain in the fourth quarter of 2002), in
the margin of our natural gas pipelines and plants segment. 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 and August 2003, we entered into
additional derivative financial instruments to continue to hedge our exposure
during 2004 to changes in natural gas prices relating to gathering activities in
the San Juan Basin. The derivatives are financial swaps on 30,000 MMBtu per day
whereby we receive an average fixed price of $4.23 per MMBtu and pay a floating
price based on the San Juan index. We are accounting for these derivatives as
cash flow hedges under SFAS No. 133. As of September 30, 2003, the fair value of
all of our San Juan gathering cash flow hedges was a liability of $2.4 million,
as the market price at that date was higher than the hedge price of $4.23. For
the nine months ended September 30, 2003, we reclassified $8.4 million of
unrealized accumulated loss related to these derivatives from accumulated other
comprehensive income as a decrease in revenue 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.

64

In connection with our GulfTerra Intrastate Alabama operations, we have
fixed price contracts with specific customers for the sale of predetermined
volumes of natural gas for delivery over established periods of time. We have
entered into cash flow hedges in 2002 and 2003 to offset the risk of increasing
natural gas prices for our purchases to satisfy these sales contracts. As of
September 30, 2003, the fair value of these cash flow hedges was a liability of
$11 thousand, as the market price at that date was lower than the hedge price of
$5.20. For the nine months ended September 30, 2003, we reclassified $223
thousand of unrealized accumulated gain related to these derivatives from
accumulated other comprehensive income to earnings as a reduction of cost of
natural gas. 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 September 30, 2003, the fair value of its interest rate swap was a liability
of $0.5 million, as the market interest rate was lower than the hedge rate of
4.99%, resulting in accumulated other comprehensive loss of $0.5 million. We
included our 36 percent share of this liability of $0.2 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 three months. Additionally, we have recognized as a reduction of income
our 36 percent share of Poseidon's realized loss of $1.3 million for the nine
months ended September 30, 2003, or $0.5 million, through our earnings from
unconsolidated affiliates.

We estimate the entire $3.0 million of unrealized losses included in
accumulated other comprehensive income at September 30, 2003, will be classified
from accumulated other comprehensive income as a reduction to earnings over the
next 15 months and approximately $2.9 million will be reclassed as a reduction
to earnings over the next twelve months. When our derivative financial
instruments are settled, the related amount in accumulated other comprehensive
income is recorded in the income statement in operating revenues, cost of
natural gas and others products, or interest and debt expense, depending on the
item being hedged. The effect of reclassifying these amounts to the income
statement line items is recording our earnings for the period at the "hedged
price" under the derivative financial instruments.

In July 2003, to achieve a better mix of fixed rate debt and variable rate
debt, we entered into an eight-year interest rate swap agreement to provide for
a floating interest rate on $250 million out of $480 million of our 8 1/2%
senior subordinated notes due 2011. With this swap agreement, we 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 under FAS No. 133. As of September 30, 2003, the fair value of the
interest rate swap was a liability, included in non-current liabilities, of
approximately $2.2 million. The fair value of the hedged debt decreased by the
same amount.

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).

65

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 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.

66

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 the portion of our partnership agreement relating to our
Series F units. See Part I, Item 2, Management's Discussion and Analysis,
"General Partner Relationship" and "Liquidity and Capital Resources" for
discussions of how these changes affect our common units, which is incorporated
herein by reference.

In October 2, 2003, in connection with the investment by Goldman, Sachs &
Co., a wholly owned subsidiary of Goldman Sachs Group Inc., of a 9.9 percent
membership interest in our generally partner, Goldman Sachs purchased 3,000,000
of our common units from us for $112 million in a transaction exempt from
registration pursuant to Section 4(2) of the Securities Act of 1933, as amended,
as a transaction not involving any public offering.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

Each exhibit identified below is filed as part of this document. Exhibits
not incorporated by reference to a prior filing are designated by a "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" represent a management
contract or compensatory plan or arrangement.

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 August 18, 2003 to file an
unaudited balance sheet of GulfTerra Energy Company L.L.C., our general partner,
as of June 30, 2003.

We filed a current report on Form 8-K dated August 21, 2003 to file
exhibits to the Registration Statement on Form S-3 (Registration No. 333-81772),
relating to the issuance of 507,278 common units.

We filed a current report on Form 8-K dated August 26, 2003 to file
exhibits to the Registration Statement on Form S-3 (Registration No. 333-81772)
relating to the issuance and sale of up to 8,329,679 common units representing
limited partnership interests in us from time to time in connection with the
conversion of our Series F convertible units.

We filed a current report on Form 8-K dated October 10, 2003 to file (a)
the amendment to our partnership agreement, (b) our amended credit agreement,
(c) material agreements relating to Goldman Sachs' investment in us and our
general partner and (d) a consent from independent petroleum engineers.

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.

70

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

GULFTERRA ENERGY PARTNERS, L.P.

Date: November 3, 2003 By: /s/ KEITH B. FORMAN
------------------------------------
Keith B. Forman
Vice President and Chief Financial
Officer
(Principal Financial Officer)

Date: November 3, 2003 By: /s/ KATHY A. WELCH
------------------------------------
Kathy A. Welch
Vice President and Controller
(Principal Accounting Officer)

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INDEX TO EXHIBITS