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 MARCH 31, 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) 676-6152

Former name: EL PASO ENERGY PARTNERS, L.P.

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 47,484,314 common units outstanding as of May 12, 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.
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GULFTERRA ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT UNIT AMOUNTS)
(UNAUDITED)

See accompanying notes.

2

GULFTERRA ENERGY PARTNERS, L.P.

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

See accompanying notes.

3

GULFTERRA ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(IN THOUSANDS)
(UNAUDITED)

COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

See accompanying notes.

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GULFTERRA ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

In May 2003, we changed our name to GulfTerra Energy Partners, L.P. from El
Paso Energy Partners, L.P. and reorganized our general partner. Our one percent
general partner interest is now owned by GulfTerra Energy Company, L.L.C.
replacing El Paso Energy Partners Company as the general partner. In connection
with our name change, we have also changed the names of several subsidiaries as
listed in the table below.

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission (SEC).
Because this is an interim period filing presented using a condensed format, it
does not include all of the disclosures required by generally accepted
accounting principles. You should read it along with our 2002 Annual Report on
Form 10-K, which includes a summary of our significant accounting policies and
other disclosures. The financial statements as of March 31, 2003, and for the
quarters ended March 31, 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. Due to the seasonal nature of some of our businesses, information for
interim periods may not depict the results of operations for the entire year. In
addition, prior period information presented in these financial statements
includes reclassifications which were made to conform to the current period
presentation. These reclassifications have no effect on our previously reported
net income or partners' capital. We have also reflected the results of
operations from our Prince assets disposition as discontinued operations in the
quarter ended March 31, 2002.

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

Accounting for Asset Retirement Obligations

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

We recorded a $1.7 million increase to income as a cumulative effect of
accounting change upon our adoption of SFAS No. 143. We also reversed $7.1
million negative salvage value and recorded non-current retirement assets
totaling $3.1 million with useful lives ranging from 11 to 19 years to property,
plant and equipment, accumulated depreciation of $2.8 million, and retirement
obligations totaling $5.7 million to noncurrent liabilities.
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As generally used in the energy industry and in this document, the following
terms have the following meanings:

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

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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. Also, we believe that the life or underlying
reserves cannot be estimated. Therefore, we have not recorded any liabilities
relating to our assets, other than the liability associated with the plug and
abandonment of offshore wells.

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

Reporting Gains and Losses from the Early Extinguishment of Debt

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

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 will impact any exit or
disposal activities that we initiate after January 1, 2003 and we will 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 for the quarter ended March 31, 2003.

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 for all guarantees issued after
December 31, 2002, including financial, performance, and fair value guarantees.
Our initial application of this standard for the quarter ended March 31, 2003
did not have an effect on our financial position or results of operations. We
have provided disclosures relating to our guarantee activities in Note 6.

Consolidation of Variable Interest Entities

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

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Accounting for Stock-Based Compensation

We use the intrinsic value method established in Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, to value
unit options issued to former employees of our general partner and our board of
directors under our Omnibus Plan and Director Plan. For the quarters ending
March 31, 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.

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 the fiscal
years ending after December 15, 2002. We have decided that we will continue to
use APB No. 25 to value our stock-based compensation and will include data
providing the pro forma income impacts of using the fair value method as
required by SFAS No. 148.

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 are not
indicative of future amounts.

2. ACQUISITION

During the first quarter of 2003, we recorded additional purchase price
adjustments of approximately $4.7 million on our April 2002 EPN Holding asset
acquisition related to natural gas imbalances. The following table summarizes
our revised allocation of the fair values of the assets acquired and liabilities
assumed at

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April 8, 2002. Our allocation among the assets acquired is based on the results
of an independent third-party appraisal.

3. PARTNERS' CAPITAL

Cash distributions

In February 2003, we paid cash distributions of $0.675 per common and
Series C unit for an aggregate of $37.1 million and our general partner received
incentive distributions of $14.6 million. In April 2003 we declared a cash
distribution of $0.675 per common unit for the quarter ended March 31, 2003,
which we will pay on May 15, 2003, to holders of record as of April 30, 2003.
Also in May 2003, we will pay our general partner $15.5 million in incentive
distributions. At the current distribution rates, our general partner receives
approximately 29 percent of the total cash distributions we pay.

Public offering of common units

In April 2003, we issued 3,450,000 common units at the public offering
price of $31.35 per unit. We used the net cash proceeds of approximately $103
million to temporarily reduce indebtedness outstanding under our $600 million
revolving credit facility and pay fees and expenses associated with this
offering. In addition, our general partner contributed approximately $1 million
of our Series B preference units to us in April 2003 in order to maintain its
one percent general partner interest.

Other

We have reflected the issuance of our restricted units to non-employee
directors of our Board of Directors under the 1998 Unit Option Plan for
Non-Employee Directors as deferred compensation and as an increase in common
units. This deferred compensation was allocated 1% to our general partner and
99% to our limited partners and is being amortized over the vesting period of
the restricted units. The unamortized amount of our total deferred compensation
as of March 31, 2003, was approximately $0.9 million.

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4. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

5. FINANCING TRANSACTIONS

CREDIT FACILITIES

Our credit facility consists of two parts: a $600 million revolving credit
facility maturing in 2004 and a $160 million senior secured term loan maturing
in 2007. Our credit facility and the GulfTerra Holding V, L.P. (GulfTerra
Holding, formerly known as EPN Holding) term credit facility are guaranteed by
us and all of our subsidiaries, except for our unrestricted subsidiaries
(Matagorda Island Area Gathering System, Arizona Gas Storage, L.L.C. and
GulfTerra Arizona Gas, L.L.C., formerly known as EPN Arizona Gas, L.L.C.), and
by GulfTerra Energy Finance Corporation (formerly known as El Paso Energy
Partners Finance Corporation) and our general partner, and are collateralized
with substantially all of our assets (excluding our unrestricted subsidiaries)
and our general partner's general and administrative services agreement. The
interest rates we are charged on each of these credit facilities are determined
using one of two indices that include (i) a variable base rate (equal to the
greater of the prime rate as determined by JP Morgan Chase Bank, the federal
funds rate plus 0.5% or the Certificate of Deposit (CD) rate as determined by JP
Morgan Chase Bank increased by 1.00%); or (ii) LIBOR.

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

Revolving Credit Facility

As of March 31, 2003, we had $471 million outstanding on our revolving
credit facility at an average interest rate of 3.15%. The total amount available
to us at March 31, 2003 under this facility is $80 million. The amounts
outstanding under our revolving credit facility bear interest at our option at
either (i) 0.75% over the variable base rate described above; or (ii) 1.75% over
LIBOR.

Senior Secured Term Loan

As of March 31, 2003, we had $160 million outstanding under our senior
secured term loan with an average interest rate of 5.22%. The amounts
outstanding under our senior secured term loan bear interest at our option at
either (i) 2.25% over the variable base rate described above; or (ii) 3.50% over
LIBOR.

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GulfTerra Holding Term Credit Facility

As of March 31, 2003, the outstanding balance under the GulfTerra Holding
term credit facility was $160 million with an average interest rate of 3.57%.
The balance outstanding under the GulfTerra Holding term credit facility bears
interest at our option at either (i) 1.00% over the variable base rate described
above; or (ii) 2.25% over LIBOR.

Senior Secured Acquisition Term Loan

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

SENIOR SUBORDINATED NOTES

Each issue of our senior subordinated notes is subordinated in right of
payment to all existing and future senior debt including our existing credit
facilities. Additionally, our senior subordinated notes include provisions that,
among other things, restrict our subsidiaries' ability to acquire assets, incur
additional indebtedness or liens, sell assets, acquire or be acquired by other
companies, and enter into sale and lease back transactions unless we meet the
financial ratios and other specific conditions provided in these covenants.
These restrictive covenants will be suspended should our notes be rated Baa3 or
higher by Moody's or BBB- or higher by S&P.

In March 2003, we issued $300 million in aggregate principal amount of
8 1/2% senior subordinated notes. These notes bear interest of 8 1/2% per year,
payable semi-annually in June and December, and mature in June 2010. We used the
proceeds of approximately $293 million, net of issuance costs, to repay $237.5
million of indebtedness under our senior secured acquisition term loan and to
temporarily repay $56.5 million of the balance outstanding under our revolving
credit facility. These notes are subject to a registration rights agreement
under which we are required to file an exchange offer registration statement on
Form S-4 with the SEC on or prior to July 8, 2003. The registration statement on
Form S-4 must then become effective on or prior to September 1, 2003 or we will
be subject to penalties of approximately $15,000 per week until a registration
statement is filed with the SEC and declared effective. We may, at our option,
prior to June 1, 2006, redeem up to 33 percent of the originally issued
aggregate principal amount of these notes at a redemption price of 108.50
percent of the principal amount. On or after June 1, 2007, we may redeem all or
part of these notes at 104.25 percent of the principal amount.

OTHER CREDIT FACILITIES

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 $127 million outstanding, that may
restrict its ability to pay distributions to its owners.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of the
$127 million outstanding under its credit facility at 3.49% through January
2004. Under its credit facility, Poseidon currently pays an additional 1.50%
over LIBOR resulting in an effective interest rate of 4.99% on the hedged
notional amount. As of March 31, 2003, the remaining $52 million was at an
average interest rate of 2.81%.

As of March 31, 2003, Deepwater Gateway, an unconsolidated affiliate in
which we have a 50 percent joint venture ownership interest, had $67 million
outstanding under its project finance loan at an average interest rate of 3.11%.
This project finance loan will mature in July 2004 unless construction is
completed before that time and Deepwater Gateway meets other specified
conditions, in which case the project finance

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loan will convert into a term loan with a final maturity date of July 2009. Upon
conversion of the project finance loan to a term loan, Deepwater Gateway will be
required to maintain a debt service reserve equal or greater than the projected
principal, interest and fees due on the term loan for the immediately succeeding
six month period. Prior to conversion to the term loan Deepwater Gateway is
prohibited from making distributions.

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 March 31, 2003 (in thousands):

2003........................................................ $ 5,000
2004........................................................ 476,000
2005........................................................ 165,000
2006........................................................ 5,000
2007........................................................ 140,000
Thereafter.................................................. 1,155,000
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Total long-term debt and other financing obligations,
including current maturities........................... $1,946,000
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6. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we were named defendants in actions brought by Jack
Grynberg on behalf of the U.S. Government under the False Claims Act. Generally,
these complaints allege an industry-wide conspiracy to underreport the heating
value as well as the volumes of the natural gas produced from federal and Native
American lands, which deprived the U.S. Government of royalties. The plaintiff
in this case seeks royalties that he contends the government should have
received had the volume and heating value of natural gas produced from royalty
properties been differently measured, analyzed, calculated and reported,
together with interest, treble damages, civil penalties, expenses and future
injunctive relief to require the defendants to adopt allegedly appropriate gas
measurement practices. No monetary relief has been specified in this case. These
matters have been consolidated for pretrial purposes (In re: Natural Gas
Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming,
filed June 1997). In May 2001, the court denied the defendants' motions to
dismiss. Discovery is proceeding. Our costs and legal exposure related to those
lawsuits and claims are not currently determinable.

Will Price (formerly Quinque). We have also been named defendants in
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. Quinque has been
dropped as a plaintiff and Will Price has been added. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
plaintiff in this case seeks certification of a nationwide class of natural gas
working interest owners and natural gas royalty owners to recover royalties that
the plaintiff contends 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. Our costs and legal exposure related to this lawsuit 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.

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During 2000, Leapartners, L.P. filed a suit against El Paso Field Services
and others in the District Court of Loving County, Texas, alleging a breach of
contract to gather and process natural gas in areas of western Texas related to
an asset now owned by GulfTerra Holding. In May 2001, the court ruled in favor
of Leapartners and entered a judgment against El Paso Field Services of
approximately $10 million. El Paso Field Services has filed an appeal with the
Eighth Court of Appeals in El Paso, Texas. Briefs have been filed and oral
arguments were heard in November 2002. Review by the Court of Appeals is
expected in 2003.

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

In December 2000, a 30-inch natural gas pipeline jointly owned by GulfTerra
Intrastate, L.P. (GulfTerra Intrastate, formerly known as El Paso Energy
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. In September 2002, an agreement was
reached to settle the claims of two plaintiffs (including one of the insurers).
Trial of five of the six remaining claims is set to commence in May 2003.

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 addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we will establish the necessary
accruals. As of March 31, 2003, we had no reserves for our legal matters.

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

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Environmental

Each of our operating segments is subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These laws and regulations are applicable to each segment and require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of March 31,
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. El Paso Corporation has agreed to indemnify us for all the known and
unknown environmental liabilities related to the assets we purchased as part of
the November 2002 San Juan assets acquisition 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. In addition, we have been indemnified by third
parties for remediation costs associated with other assets we have purchased. We
expect to make capital expenditures for environmental matters of approximately
$10 million in the aggregate for the years 2003 through 2007, primarily to
comply with clean air regulations.

While the outcome of our outstanding environmental matters cannot be
predicted with certainty, based on the information known to date and our
existing accruals, we do not expect the ultimate resolution of these matters
will have a material adverse effect on our financial position, results of
operations or cash flows. It is possible that new information or future
developments could require us to reassess our potential exposure related to
environmental matters. We may incur significant costs and liabilities in order
to comply with existing environmental laws and regulations. It is also possible
that other developments, such as increasingly strict environmental laws and
regulations and claims for damages to property, employees, other persons and the
environment resulting from our current or past operations, could result in
substantial costs and liabilities in the future. As this information becomes
available, or relevant developments occur, we will adjust our accrual amounts
accordingly. While there are still uncertainties relating to the ultimate costs
we may incur, based upon our evaluation and experience to date, we believe our
current reserves are adequate.

Rates and Regulatory Matters

Marketing Affiliate NOPR. 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 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 hearing was held
in May 2002, providing an opportunity to comment further on the NOPR. Following
the conference, we filed additional comments. At this time, we cannot predict
the outcome of the NOPR, but adoption of the regulations in the form proposed
would, at a minimum, place additional administrative and operational burdens on
us.

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

Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. The FERC is now

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reviewing whether negotiated rates should be capped, whether or not the
"recourse rate" (a cost-of-service based rate) continues to safeguard against a
pipeline exercising market power, and as other issues related to negotiated rate
programs. At this time, we cannot predict the outcome of this NOI.

Cash Management NOPR. In August 2002, the FERC issued a NOPR requiring that
all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth the
duties and responsibilities of cash management participants and administrators;
the methods of calculating interest and for allocating interest income and
expenses; and the restrictions on deposits or borrowings by money pool members.
The NOPR also requires specified documentation for all deposits into, borrowings
from, interest income from, and interest expenses related to, these
arrangements. Finally, the NOPR proposes that as a condition of participating in
a cash management or money pool arrangement, the FERC regulated entity must
maintain a minimum proprietary capital balance of 30 percent, and the FERC
regulated entity and its parent must maintain investment grade credit ratings.
In August 2002 comments were filed. The FERC held a public conference in
September 2002. Representatives of companies from the gas and electric
industries participated on a panel and uniformly agreed that the proposed
regulations should be revised substantially and commented that the proposed
capital balance and investment grade credit rating requirements would be
excessive. At this time, we cannot predict the outcome of this NOPR.

Also in August 2002, FERC's Chief Accountant issued an Accounting Release,
to be effective immediately, providing guidance on how companies should account
for money pool arrangements and the types of documentation that should be
maintained for these arrangements. However, the Accounting Release did not
address the proposed requirements that the FERC regulated entity maintain a
minimum proprietary capital balance of 30 percent and that the entity and its
parent have investment grade credit ratings. Requests for rehearing were filed
in August 2002. The FERC has not yet acted on the rehearing requests.

If the cash management NOPR is adopted by the FERC, our HIOS and Petal
interstate facilities will no longer be permitted to participate in a money pool
or cash management program. As a result, more frequent distributions or equity
contributions may be needed in anticipation of monthly cash flow requirements
for those interstate facilities. Also, separate credit facilities and resources
may be required to support the capital and day-to-day activities for the
interstate facilities separate from other of our subsidiaries and our primary
bank accounts.

Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. In
April 2002, FERC and the Department of Transportation, Office of Pipeline Safety
convened a technical conference to discuss how to clarify, expedite, and
streamline permitting and approvals for interstate pipeline reconstruction in
the event of disaster, whether natural or otherwise. In January 2003, FERC
issued a NOPR proposing to (1) expand the scope of construction activities
authorized under a pipeline's blanket certificate to allow replacement of
mainline facilities; (2) authorize a pipeline to commence reconstruction of the
affected system without a waiting period; and (3) authorize automatic approval
of construction that would be above the normal cost ceiling. Comments on the
NOPR were filed on February 27, 2003. At this time we cannot predict the outcome
of this NOPR.

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
due on April 30, 2003. At this time, we cannot predict the outcome of this NOPR.

Other Regulatory Matters. HIOS is subject to the jurisdiction of the FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. HIOS operates under a separate 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. HIOS' filing reflects zero rate base; therefore, we requested a
management fee in place
14

of a return on rate base. We requested the rates be effective February 1, 2003,
but the FERC suspended the rate increase until July 1, 2003, subject to refund.
We have responded, and are continuing to respond, as new requests are received,
to the FERC staff's data requests. The FERC has scheduled a hearing on this
matter commencing November 17, 2003.

During the latter half of 2002, we experienced a significant variance
between the fuel usage on HIOS and the fuel collected from our customers. We
believe a series of events may have contributed to this variance, including two
major storms that hit the Gulf Coast Region (and these assets) in late September
and early October of 2002. We are taking numerous steps to determine the cause
of the fuel differences, including a review of receipt and delivery measurement
data. At March 31, 2003, we had recorded fuel differences of approximately $8.2
million included in other non-current assets. Depending on the outcome of our
review, we may require FERC approval to collect the fuel differences. At this
time we are not able to determine what amount, if any, may be collectible from
our customers.

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

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 has been granted
and is pending before the FERC.

In July 2002, Falcon Gas Storage also requested late intervention and
rehearing of the order. Falcon asserts that GulfTerra Texas' imbalance penalties
and terms of service preclude third parties from offering imbalance management
services. Meanwhile in December 2002, GulfTerra Texas amended its Statement of
Operating Conditions to provide shippers the option of resolving daily
imbalances using a third-party imbalance service provider. Falcon objected to
the changes, complaining that imbalance resolution is the lowest priority of
service. GulfTerra Texas responded to Falcon's objection and untimely
intervention, repeating its request that Falcon's intervention be dismissed.

In December 2002, GulfTerra Texas requested FERC approval of market-based
rates for interstate gas storage services performed at its Wilson storage
facility. The filing was in compliance with a requirement to rejustify its
existing rates or request new rates by December 20, 2002. The requested
market-based rates are currently subject to refund. 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. We filed a response stating that their complaint is not
relevant to the rate case, that a severance of this issue has been requested in
the GulfTerra Texas pipeline rate case, and requesting a dismissal of their
intervention. This matter is pending before the FERC.

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

15

Guarantees

We conduct our businesses through our wholly-owned subsidiaries, joint
ventures and other ownership arrangements to construct, operate and finance the
development of our onshore and offshore midstream energy businesses. Third
parties routinely require us to provide performance and financial guarantees to
support the obligations of our subsidiaries under contracts entered into in
connection with our business. The events and circumstances that may require us,
on behalf of our subsidiaries, to perform under these guarantees include
nonperformance by our joint ventures and other affiliates of services, such as
gathering, transportation, processing and storage services, and nonpayment of
contractual obligations.

As of March 31, 2003, we had approximately $137.9 million of performance
guarantees in connection with the activities of our joint ventures and other
affiliates. Such contingent obligations are not recorded in our consolidated
financial statements unless they become payable. The most significant of our
performance guarantee commitments is related to the construction of the Marco
Polo TLP facility. We have guaranteed the payment of approximately $51 million
as of March 31, 2003, under the turnkey construction contract between Deepwater
Gateway and the construction contractor. We are obligated to perform under this
guarantee should Deepwater Gateway fail to satisfy its obligations by drawing
under its $155 million project finance loan or Deepwater Gateway's joint venture
partners fail to perform under their joint venture agreement. Our commitment
under this guarantee is scheduled to expire in 2003.

We are also obligated under an agreement with certain lenders to make
payments on behalf of Deepwater Gateway to the extent of any distributions we or
any of our subsidiaries receive from Deepwater Gateway up to $22.5 million, if
Deepwater Gateway defaults on its payment obligations under its project finance
loan. Neither we nor any of our subsidiaries have received any distributions
from Deepwater Gateway as March 31, 2003.

Other Matters

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.

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.

7. 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 our El Paso Intrastate Alabama (EPIA)
pipeline and sales of liquids associated with our interest in the Indian Basin
processing plant, are at spot market or forward market prices. We use futures,
forward contracts, and swaps to limit our exposure to fluctuations in the
commodity markets and allow for a fixed cash flow stream from these activities.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices relating to gathering
activities in the San Juan Basin in anticipation of our acquisition of the San
Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby
we receive a fixed price of $3.525 per MMBtu and pay a floating price based on
the San Juan index. Beginning with the acquisition date in November 2002, we are
accounting for this derivative as a cash flow hedge under SFAS No. 133. In
February 2003, we entered into an additional derivative financial instrument to
continue to hedge our exposure during 2004 to changes in natural gas prices
relating to gathering activities in the San Juan Basin. The derivative is a
financial swap on 15,000 MMBtu per day whereby we receive a fixed price of $3.95
per MMBtu and pay a floating price based on the San Juan index. We are
accounting for this derivative as a

16

cash flow hedge under SFAS No. 133. As of March 31, 2003, the fair value of
these cash flow hedges was a liability of $10.8 million. For the quarter ended
March 31, 2003, we reclassified a loss of $4.1 million from accumulated other
comprehensive income to earnings. No ineffectiveness exists in our hedging
relationship because all purchase and sale prices are based on the same index
and volumes as the hedge transaction. We estimate the entire amount will be
reclassified from accumulated other comprehensive income to earnings over the
next 21 months and approximately $8.9 million will be reclassified to earnings
over the next twelve months.

At March 31, 2003, in connection with our EPIA operations, we have fixed
price contracts with specific customers for the sale of predetermined volumes of
natural gas for delivery over established periods of time. We entered into cash
flow hedges in 2002 and 2003 to offset the risk of increasing natural gas
prices. As of March 31, 2003, the fair value of these cash flow hedges was an
asset of approximately $192 thousand. For the quarter ended March 31, 2003, the
majority of these cash flow hedges expired and we reclassified a gain of $210
thousand from accumulated other comprehensive income to earnings. No
ineffectiveness exists in our hedging relationship because all purchase and sale
prices are based on the same index and volumes as the hedge transaction. We
estimate the entire amount will be reclassified from accumulated other
comprehensive income to earnings over the next quarter.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of its
$185 million variable rate revolving credit facility at 3.49% over the life of
the swap. Under its credit facility, Poseidon pays an additional 150 basis
points over LIBOR resulting in an effective interest rate at 4.99% on the hedged
notional amount. As of March 31, 2003, the fair value of its interest rate swap
was a liability of $1.0 million resulting in accumulated other comprehensive
loss of $1.0 million. We included our 36 percent share of this liability of $0.4
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 nine months. Additionally, we have
recognized in income our 36 percent share of Poseidon's realized loss of $0.4
million for the quarter ended March 31, 2003, or $0.1 million, through our
earnings from unconsolidated affiliates.

The counterparty for our San Juan hedging activities is J. Aron and
Company, a subsidiary of Goldman Sachs. We do not require collateral and do not
anticipate non-performance by this counterparty. The counterparty for our EPIA
hedging activities is El Paso Merchant Energy, an affiliate of our general
partner. We do not require collateral and do not anticipate non-performance by
this counterparty. The counterparty for Poseidon's hedging activity is Credit
Lyonnais. Poseidon does not require collateral and does not anticipate
non-performance by this counterparty.

8. 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 reflect
neither the results of operations for the Prince assets nor the related assets
held for sale.

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

17

alternative to net income as an indicator of our operating performance. EBITDA
may not be a comparable measurement among different companies. Following are
results as of and for the periods ended March 31:

QUARTER ENDED MARCH 31, 2003

QUARTER ENDED MARCH 31, 2002

- ----------

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

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9. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We hold investments in various affiliates which we account for using the
equity method of accounting. Summarized financial information for these
investments are as follows:

QUARTER ENDED MARCH 31, 2003
(IN THOUSANDS)

QUARTER ENDED MARCH 31, 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.

19

10. 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.

In the first quarter of 2003, our related party revenue was 11 percent of
total revenue compared to 30 percent in the first quarter of 2002. Our total
revenues for the first quarter of 2003 have increased as a result of our
acquisitions during 2002. Also, we have undertaken efforts to reduce our related
party revenue with affiliates of El Paso Corporation by replacing our
month-to-month, market price sales of natural gas with similar arrangements with
third parties. Revenue from these types of sales for the first quarter of 2003
were approximately $3 million compared to approximately $22.2 million in the
fourth quarter of 2002.

Revenues received from related parties

Our revenues from related parties increased as a result of our April 2002
EPN Holding transaction in which we acquired gathering, transportation and
processing contracts with affiliates of our general partner. Our expenses paid
to related parties increased as a result of our April 2002 EPN Holding
transaction and November 2002 San Juan transaction.

Other Matters

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 6, Commitments and
Contingencies, Legal Proceedings. Some of our agreements obligate certain
indirect subsidiaries of El Paso Corporation to pay for capital costs related to
maintaining assets which were acquired by us, if such costs exceed negotiated
thresholds. We have made no such claims for reimbursement to date but may make
claims based on our 2002 expenditures and on our expected 2003 expenditure
requirements.

We have also entered into capital contribution arrangements with regulated
pipelines owned by El Paso Corporation in the past, and will most likely do so
in the future, as part of our normal commercial activities in the Gulf of
Mexico. Regulated pipelines often contribute capital toward the construction
costs of gathering

20

facilities owned by others which are connected to their pipelines. We have
agreements with ANR Pipeline Company and Tennessee Gas Pipeline Company under
which we will receive a total of approximately $25 million of capital toward the
construction of gathering pipelines to the Marco Polo, Phoenix and Medusa
discoveries, payable over the next eighteen months.

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

At March 31, 2003, and December 31, 2002, our accounts receivable due from
related parties was $75.0 million and $83.8 million. At March 31, 2003 and
December 31, 2002, our accounts payable due to related parties was $107.9
million and $86.1 million.

21

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:

In connection with the San Juan assets acquisition in November 2002, we
acquired a 50 percent interest in Coyote Gas Treating L.L.C. As part of this
transaction we assumed a note receivable due from our unconsolidated affiliate,
Coyote, for $17.1 million.

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.
The present value of the amounts due from El Paso Corporation were classified as
follows:

22

11. GUARANTOR FINANCIAL INFORMATION

As of March 31, 2003, our revolving credit facility, GulfTerra Holding term
credit facility and senior secured term loan are guaranteed by each of our
subsidiaries, excluding our unrestricted subsidiaries (Matagorda Island Area
Gathering System, Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas,
L.L.C.), and our general partner, and are collateralized by our general
partner's general and administrative services agreement and substantially all of
our assets. In addition, all of our senior subordinated notes are jointly,
severably, fully and unconditionally guaranteed by us and all of our
subsidiaries, excluding our unrestricted subsidiaries. The consolidating
eliminations column on our condensed consolidating balance sheets below
eliminate 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 eliminate earnings from our consolidated affiliates.

Non-guarantor subsidiaries as of and for the quarter ended March 31, 2003,
consisted of our unrestricted subsidiaries. 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.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE QUARTER ENDED MARCH 31, 2003

23

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE QUARTER ENDED MARCH 31, 2002

24

CONDENSED CONSOLIDATING BALANCE SHEETS
MARCH 31, 2003

25

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2002

26

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE QUARTER ENDED MARCH 31, 2003

27

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE QUARTER ENDED MARCH 31, 2002

28

12. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

29

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.

NAME CHANGE

In May 2003 we changed our name to GulfTerra Energy Partners, L.P. (NYSE:
GTM) from El Paso Energy Partners, L.P. (NYSE: EPN). In connection with our name
change, we have also changed the names of several subsidiaries. See Note 1.
Financial Statements. Our new name reflects the breadth and depth of our
business activities, including our pipelines and platforms in the waters of the
Gulf of Mexico to thousands of miles of gathering and transportation lines in
the southwest, our asset base spans the midstream.

The Gulf portion of our new name represents our origins ten years ago
offshore in the Gulf of Mexico -- the extensive infrastructure base we have
built over the past decade to meet the needs of Gulf producers and the near
limitless potential remaining for growth in the critically important Deep Water
trend of the Gulf of Mexico.

The Terra portion of our name reflects the other aspect of our diverse
midstream asset base including the pipelines, processing and treating plants,
and storage facilities located onshore. Terra also represents the rock-solid
strategy that has delivered years of outstanding results for our unitholders.

GENERAL PARTNER RELATIONSHIP

Our corporate governance structure and independence initiatives

We continually strive to improve our corporate governance model. 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 May 2003, we have implemented the following:

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

- established a governance and compensation committee of our board of
directors consisting solely of independent directors;

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

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

- modified our partnership agreement to: (1) eliminate El Paso
Corporation's right to vote its common units with respect to the removal
of the general partner; (2) increase the common unit vote to 67 percent
from 55 percent to remove the general partner; and (3) require the
unanimous vote of our general partner's board of directors to voluntarily
file the general partner or the partnership into bankruptcy;

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

- reorganized our structure, further reducing our interrelationships with
El Paso Corporation, into GulfTerra Energy Company, L.L.C., a Delaware
limited liability company that is required to have:

- no material assets other than its interests in us;

- no material operations other than those relating to our operations;

- no material debt or other obligations other than those owed to us or our
creditors;

30

- no material liens other than those securing obligations owed to us or
our creditors; and

- no employees.

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

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

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

Under the partnership agreement, our general partner has agreed not to
voluntarily withdraw as general partner prior to December 31, 2002. Now that
this obligation has expired, our general partner can withdraw with 90 days
notice. We have no employees today, a condition that is common among MLPs.
Although this arrangement has worked well for us in the past and continues to
work well for us, we are evaluating the direct employment of the personnel who
manage the day-to-day operations of our assets.

Our relationship with El Paso Corporation

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

- owns 100 percent of our general partner; however, El Paso Corporation has
publicly announced that it intends to sell up to ten percent of its
general partner interest.

- is a significant stake-holder in us -- it owns approximately 26.5
percent, or 11,674,245, of our common units (which decreased to 24.6
percent as a result of our April 2003 common unit offering), all
10,937,500 of our newly issued Series C units, which we issued in
November 2002 for $350 million, all 125,392 of our outstanding Series B
preference units, with a liquidation value of approximately $161 million
at March 31, 2003 (which decreased to 124,584 Series B preference units,
with a liquidation value of approximately $160 million as a result of El
Paso Corporation's contribution to us of approximately $1 million in
liquidation value of Series B preference units to maintain its one
percent general partner interest in conjunction with our April 2003
common unit offering) and our one percent general partner interest.

- 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.

- has in the past publicly announced its intention to use us as its primary
vehicle for growth and development of its midstream energy business;
however, El Paso Corporation is neither contractually nor legally bound
to use us as its primary vehicle for growth and development of midstream
energy assets, and may reconsider its relationship with us any time,
without notice.

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

RELATED PARTY TRANSACTIONS

In our normal course of business we enter into transactions with various
entities controlled directly or indirectly by El Paso Corporation. For the
quarter ended March 31, 2003, $10.8 million of our related party revenue came
from El Paso Merchant Energy North America Company (Merchant Energy), a direct
subsidiary of El Paso Corporation. In November 2002, El Paso Corporation
announced its intention to exit the energy trading business. Accordingly, we are
in the process of replacing our month-to-month, market priced sales of natural
gas to Merchant Energy, which in the quarter ended March 31, 2003 represented
revenue of
31

approximately $3.0 million, reduced from $22.2 million for the fourth quarter
2002, with similar arrangements with third parties. In addition, Merchant Energy
could sell or transfer to third parties the natural gas transportation and
storage agreements they have with us, or Merchant Energy could request a
cancellation of the transportation and storage agreements prior to expiration of
the relevant agreements. In the quarter ended March 31, 2003, these agreements
represented revenue of approximately $7.8 million. As of May 2003, Merchant
Energy continues to fully utilize these agreements.

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 will receive a fee of $1.5 million per year
for transportation on one of our NGL pipelines. See Part I, Financial
Information, Note 10 for a further discussion of our related party transactions.

LIQUIDITY AND CAPITAL RESOURCES

Our ability to execute our growth strategy and complete our projects is
dependent upon our access to the capital necessary to fund our projects and
acquisitions. During the first quarter of 2003, our business and industry have
continued to experience the adverse affects of a challenging economic climate
that has persisted since 2002. Our continued success with capital raising
efforts, including the formation of joint ventures to share costs and risks,
will 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, we may adjust the timing and amounts of
projected expenditures as necessary to adapt to changes in the capital markets.

CAPITAL RESOURCES

As part of our previously announced strategy for 2003 to raise
approximately $300 million through the issuance of common units and other
equity, we issued 3,450,000 common units in April 2003 for $31.35 per unit and
received net proceeds of approximately $103 million. Additionally, our general
partner contributed approximately $1 million of liquidation value of Series B
preference units to maintain its one percent ownership interest in us, and we
retired those Series B preference units. We used the net proceeds from our
common unit offering to temporarily reduce amounts outstanding under our $600
million revolving credit facility. In addition to our common unit offering, we
are also in negotiations with unaffiliated investors regarding the potential
sale of common units and warrants or other rights to purchase common units.
While the terms of any such potential sale have not been negotiated, such
potential sale could involve an initial sale of $25 to $50 million of equity,
with warrants or other rights to purchase as much as $150 million of additional
equity over the next several years. Due to the preliminary nature of our
negotiations, we cannot assure you when or whether a transaction will be
consummated, nor of its ultimate terms.

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

32

SERIES B PREFERENCE UNITS

In connection with our public offering of 3,450,000 common units in April
2003, our general partner contributed, and we retired, 808 Series B preference
units with liquidation value of approximately $1 million, including accrued
distributions of approximately $0.2 million, to maintain its one percent general
partner interest in us.

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 scope changes or decisions to take on additional
partners. Our projection of expenditures for the quarter ended March 31, 2003 as
presented in our 2002 Annual Report on Form 10-K, was $120 million; however, our
actual expenditures were approximately $80 million. We intend to spend the
remaining amount in subsequent quarters and have included those amounts in the
table below.

The table below depicts our estimate of expenditures on projects,
acquisitions, operating lease payments and principal repayments of debt
obligations through March 31, 2004 (in millions). These expenditures are net of
anticipated project financings, contributions in aid of construction and
contributions from joint venture partners, including the anticipated formation
of a joint venture with a 50 percent partner for the development of our Cameron
Highway oil pipeline project, and project financings to fund a portion of the
construction costs. We expect to be able to fund these forecasted expenditures
from the combination of operating cash flow and funds available under our
revolving credit facility. Actual results may vary from these projections. We
are contractually committed to the Cameron Highway project whether or not we
obtain a partner or project financing.

33

DEBT REPAYMENT AND OTHER OBLIGATIONS

See Part I, Financial Information, Note 5, 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 March 31, 2003, that we believe
could affect our liquidity (in millions):

We expect to renew our revolving credit facility and raise additional
capital during the next year through the issuance of additional common units and
obtaining a partner and financing for our Cameron Highway oil pipeline project.
We expect to use the proceeds we receive from any additional capital we raise
through the issuance of additional common units to reduce amounts outstanding
under our credit facilities, to finance growth opportunities and for general
partnership purposes. Our ability to raise additional capital may be negatively
affected by many factors, including our relationship with El Paso Corporation.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $71.4 million for the quarter
ended March 31, 2003, compared to $43.2 million for the same period in 2002. The
increase was attributable to operating cash flows generated by our acquisitions
of the EPN Holding assets in April 2002 and the San Juan assets in November
2002.

CASH FROM INVESTING ACTIVITIES

Net cash used in investing activities was approximately $79.0 million for
the quarter ended March 31, 2003. Our investing activities include capital
expenditures related to the construction of the Marco Polo TLP, the Cameron
Highway oil pipeline, and the Falcon Nest fixed-leg platform. The expenditures
were partially offset by proceeds of $3.1 million from our sale of a treating
facility in February 2003.

CASH FROM FINANCING ACTIVITIES

Net cash used in financing activities was approximately $16.3 million for
the quarter ended March 31, 2003. During 2003, our cash provided by financing
activities included the issuances of long-term debt. 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.

34

ACQUISITIONS

During the first quarter of 2003, we recorded additional purchase price
adjustments of approximately $4.7 million on our April 2002 EPN Holding asset
acquisition related to natural gas imbalances. The following table summarizes
our revised allocation of the fair values of the assets acquired and liabilities
assumed at April 8, 2002. Our allocation among the assets acquired is based on
the results of an independent third-party appraisal.

CONSTRUCTION PROJECTS

We are currently constructing the following projects:

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

(1) Forecasted capital expenditures include 100% of the expected costs and are
not reduced for contributions in aid of construction, anticipated project
financings and contributions from joint venture partners. We expect to
receive from subsidiaries of El Paso Corporation the following: $2 million
from Tennessee Gas Pipeline for Medusa, $17.5 million total from El Paso
Field Services and ANR Pipeline Company for the Marco Polo pipelines ($6
million which has been received from ANR) and $6.1 million from ANR for
Phoenix.

(2) This tension leg platform is being constructed by Deepwater Gateway, L.L.C.,
our 50/50 joint venture with CalDive International. Our share of the
forecasted expenditures is approximately $112 million. Forecasted
expenditures increased 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.

(3) We have entered into a non-binding letter of intent with Valero Energy
Corporation under which Valero would acquire a 50 percent interest in the
entity we form to construct, install and own this pipeline. The formation of
the joint venture is subject to specific conditions set forth in the letter
of intent including negotiating and executing definitive documentation and
obtaining mutually acceptable financing.

NEWLY ANNOUNCED PROJECTS

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

35

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.

OTHER MATTERS

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

RESULTS OF OPERATIONS

Our business activities are segregated into four distinct operating
segments:

- Natural gas pipelines and plants;

- Oil and NGL logistics;

- Natural gas storage; and

- Platform services.

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

To the extent possible, results of operations have been reclassified to
conform to the current business segment presentation, although these results may
not be indicative of the results which would have been achieved had the revised
business segment structure been in effect during those periods. Operating
revenues and expenses by segment include intersegment revenues and expenses
which are eliminated in consolidation. For a further discussion of the
individual segments, see Part I, Financial Information, Note 8.

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

36

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 for the quarters ended:

SEGMENT RESULTS

The following table presents EBITDA by segment and in total.

37

NATURAL GAS PIPELINES AND PLANTS

We purchase natural gas from producers at the wellhead for an index price
less an amount that compensates us for gathering services. We then sell the
natural gas into the open market at points on our system at the same index
price. Accordingly, our operating revenues and costs of natural gas are impacted
by changes in energy commodity prices, while our margin is unaffected. For these
reasons, we believe that gross margin (revenue less cost of natural gas)
provides a more accurate and meaningful basis than operating revenue or cost of
natural gas for analyzing operating results for this segment.

First Quarter 2003 Compared to First Quarter 2002

Natural gas pipelines and plants margin for the quarter ended March 31,
2003, was $79.2 million higher than in the same period in 2002. Approximately
$43.0 million of the increase was due to our November 2002 purchase of the San
Juan Basin assets and approximately $36.7 million of the increase was due to our
April 2002 purchase of the EPN Holding assets. Additionally, margin increased by
approximately $1.0 million due to increased production in the Camden Hills and
Aconcagua Fields, which deliver natural gas to our Viosca Knoll system, offset
by $2.2 million of decreased production on HIOS due to natural decline in the
offshore region.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter ended March 31, 2003, were $22.2 million higher than the same period
in 2002 primarily due to our November 2002 acquisition of the San Juan Basin
assets and our April 2002 purchase of the EPN Holding assets. Excluding the
operating costs of the newly acquired assets, operating expenses decreased by
$0.8 million.

38

OIL AND NGL LOGISTICS

- ----------

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

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

First Quarter 2003 Compared to First Quarter 2002

For the quarter ended March 31, 2003, margin was $3.1 million higher than
the same period in 2002 primarily due to our November 2002 acquisition of the
Texas NGL facilities and an oil gathering system located in the deep water
regions of the Gulf of Mexico, referred to as Typhoon Oil Pipeline, which assets
contributed $2.8 million to the increase.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter ended March 31, 2003, were $1.7 million higher than the same period
in 2002 primarily due to our November 2002 acquisition of the Typhoon Oil
Pipeline and the Texas NGL facilities offset by the modification of the
operating agreement between our subsidiary and El Paso Field Services, which
reduced the amount of El Paso Field Services' monthly operating charges to us,
in connection with the April 2002 EPN Holding acquisition.

39

NATURAL GAS STORAGE

- ----------

(1) Combined injections and withdrawals volumes.

We collect fixed and variable dollars for providing storage services, some
of which is generated from customers with cashout provisions, at a tariff-based
index calculation. We incur expenses as we maintain these volumetric imbalance
receivables and payables which are valued at current gas prices. For these
reasons, we believe that gross margin (storage revenues less storage expenses)
provides a more accurate and meaningful basis for analyzing operating results
for the Natural gas storage segment.

First Quarter 2003 Compared to First Quarter 2002

For the quarter ended March 31, 2003, margin was $5.7 million higher than
the same period in 2002 primarily due to the expansion of the Petal storage
facility and our April 2002 acquisition of the Wilson storage facility lease.
Excluding the increase in margin from the Petal expansion and our acquisition of
the Wilson storage facility lease, margin was down $1.1 million primarily as a
result of a decrease in firm contracts at our Hattiesburg facility.

Operating expenses excluding depreciation, depletion, and amortization for
the quarter were $1.4 million higher than the same period in 2002 primarily due
to the acquisition of the Wilson storage facility lease in April 2002.

40

PLATFORM SERVICES

First Quarter 2003 Compared to First Quarter 2002

For the quarter ended March 31, 2003, revenues were $2.5 million lower than
in the same period in 2002 primarily due to the expiration in June 2002, in
accordance with the original contract terms, of the fixed fee portion of the
Viosca Knoll 817 platform access fee contract with one of our wholly owned
subsidiaries and the Garden Banks 72 contract expiration in December 2002.
Additionally, revenue decreased due to one time billing adjustments in 2002 for
fixed monthly platform access fees and a gas dehydration fee on the East Cameron
373 platform. The decrease was partially offset by the completion of the Falcon
Nest fixed leg platform that went into operation in March 2003. Operating
expenses for the same periods were $0.4 million higher due to higher maintenance
expenses.

OTHER, NET

First Quarter 2003 Compared to First Quarter 2002

EBITDA related to non-segment activity for the quarter ended March 31,
2003, was $3.2 million higher than the same period in 2002 due to lower platform
access fee expense as a result of the expiration in June 2002 of the fixed fee
portion of the Viosca Knoll 817 platform access fee contract and the Garden
Banks 72 contract expiration in December 2002. These are intercompany contracts
as discussed in our Platform services segment. Additionally, revenues increased
due to higher natural gas and oil prices.

Net income (excluding interest and debt expense and cumulative affect of
accounting change, which are not allocated to our segments) for the quarter
ended March 31, 2003 was $5 million higher than the same period in 2002 due to
lower platform access fee expense and increased revenues as described above.

41

DEPRECIATION, DEPLETION, AND AMORTIZATION

Depreciation, depletion, and amortization for the quarter ended March 31,
2003, was $11.2 million higher than the same period in 2002. This increase is
primarily due to our November 2002 purchase of the San Juan Basin assets and our
April 2002 purchase of the EPN Holding assets. Further contributing to the
increase was the completion of the Petal expansion in June 2002, offset by lower
depletion on the oil and natural gas producing activities.

INTEREST AND DEBT EXPENSE

Interest and debt expense, net of capitalized interest, for the quarter
ended March 31, 2003, was approximately $22.7 million higher than the same
period in 2002. This increase is primarily due to an increase in the average
outstanding balance and the weighted average interest of our revolving credit
facility, the amounts outstanding under the GulfTerra Holding term credit
facility which we entered to purchase the EPN Holding assets in April 2002, the
$230 million of 8.5% senior subordinated notes issued in May 2002, the $200
million 10 5/8% senior subordinated notes issued in November 2002 and the $237.5
million senior secured acquisition term loan, which was repaid in March 2003
with the issuance of our $300 million 8 1/2% senior subordinated notes.
Capitalized interest for the quarter ended March 31, 2003 was $1.9 million
compared to $1.6 million for the same period in 2002.

LOSS DUE TO WRITE-OFF OF DEBT ISSUANCE COST

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

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Information, Note 6, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

See Item 1, Financial Information, Note 12, which is incorporated by
reference.

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

We have made statements in this document that constitute forward-looking
statements. These statements are subject to risks and uncertainties.
Forward-looking statements include information concerning possible or assumed
future results of operations. These statements may relate to information or
assumptions about:

- earnings per unit;

- capital and other expenditures;

- cash distributions;

- financing plans;

- capital structure;

- liquidity and cash flow;

- pending legal proceedings and claims, including environmental matters;

- future economic performance;

- operating income;

- cost savings;

- management's plans; and

- goals and objectives for future operations.

42

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 and
our Current Reports on Form 8-K.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 to changes in natural gas prices relating to gathering
activities in the San Juan Basin in anticipation of our acquisition of the San
Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby
we receive a fixed price of $3.525 per MMBtu and pay a floating price based on
the San Juan index. Beginning with the acquisition date in November 2002, we are
accounting for this derivative as a cash flow hedge under SFAS No. 133. In
February 2003, we entered into an additional derivative financial instrument to
continue to hedge our exposure during 2004 to changes in natural gas prices
relating to gathering activities in the San Juan Basin. The derivative is a
financial swap on 15,000 MMBtu per day whereby we receive a fixed price of $3.95
per MMBtu and pay a floating price based on the San Juan index. We are
accounting for this derivative as a cash flow hedge under SFAS No. 133. As of
March 31, 2003, the fair value of these cash flow hedges was a liability of
$10.8 million. For the quarter ended March 31, 2003, we reclassified a loss of
$4.1 million from accumulated other comprehensive income to earnings. No
ineffectiveness exists in our hedging relationship because all purchase and sale
prices are based on the same index and volumes as the hedge transaction. We
estimate the entire amount will be classified from accumulated other
comprehensive income to earnings over the next 21 months and approximately $8.9
million will be reclassed to earnings over the next twelve months.

At March 31, 2003, in connection with our EPIA operations, we have fixed
price contracts with specific customers for the sale of predetermined volumes of
natural gas for delivery over established periods of time. We entered into cash
flow hedges in 2002 and 2003 to offset the risk of increasing natural gas
prices. As of March 31, 2003, the fair value of these cash flow hedges was an
asset of approximately $192 thousand. For the quarter ended March 31, 2003, the
majority of these cash flow hedges expired and we reclassified a gain of $210
thousand from accumulated other comprehensive income to earnings. No
ineffectiveness exists in our

43

hedging relationship because all purchase and sale prices are based on the same
index and volumes as the hedge transaction. We estimate the entire amount will
be reclassified from accumulated other comprehensive income to earnings over the
next quarter.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the variable LIBOR based interest rate on $75 million of the
$127 million outstanding under its credit facility at 3.49% through January
2004. Under its credit facility, Poseidon pays an additional 1.50% over LIBOR
resulting in an effective interest rate at 4.99% on the hedged notional amount.
As of March 31, 2003, the fair value of its interest rate swap was a liability
of $1.0 million resulting in accumulated other comprehensive loss of $1.0
million. We included our 36 percent share of this liability of $0.4 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 nine months. Additionally, we have recognized in
income our 36 percent share of Poseidon's realized loss of $0.4 million for the
quarter ended March 31, 2003, or $0.1 million, through our earnings from
unconsolidated affiliates.

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 (Internal Controls) within 90 days of the filing date of
this annual report pursuant to Rules 13a-15 and 15d-15 under the Securities
Exchange Act of 1934 (Exchange Act).

Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

Limitations on the Effectiveness of Controls. Our management, including
the principal executive officer and principal financial officer, does not expect
that our Disclosure Controls and Internal Controls will prevent all errors and
all fraud. 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. Further, 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, and there
can be no assurance that any design will succeed in achieving its stated goals
under all potential future conditions; over time, control may become inadequate
because of changes in conditions, or the degree of compliance with the policies
or procedures may deteriorate. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and
not be detected.

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

44

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 Annual Report. The principal
executive officer and principal financial officer note that, from the date of
the controls evaluation to the date of this Annual Report, there have been no
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, subject to the limitations discussed above, 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,
particularly during the period when our periodic reports are being prepared.

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 herein, or as Exhibits to this
Annual Report, as appropriate.

45

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Financial Information, Note 6, which is incorporated herein by
reference.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

We have amended our partnership agreement, affecting our common units. See
Part I, Management's Discussion and Analysis, which is incorporated herein by
reference.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

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

48

We filed a current report on Form 8-K dated April 7, 2003 to report our
active consideration of an underwritten offering of our common units and
preliminary negotiations with unaffiliated investors for the potential sale of
common units and other equity to raise approximately $300 million.

We filed a current report on Form 8-K dated April 8, 2003 to file a one
year audited balance sheet of GulfTerra Energy Company, L.L.C. our general
partner, as of December 31, 2002, and a two year audited balance sheet of
GulfTerra Energy Finance Corporation, a subsidiary of GulfTerra Energy Partners,
L.P. as of December 31, 2002 and 2001, which were incorporated by reference into
our Registration Statement on Form S-3 (Registration No. 333-81772, No.
333-85987 and No. 333-103544).

We filed a current report on Form 8-K dated April 10, 2003 to file consents
from experts with respect to reports incorporated by reference into our
Registration Statement in Form S-3 (Registration No. 333-81772).

We filed a current report on Form 8-K dated April 11, 2003 to file exhibits
to the Registration Statement on Form S-3 (Registration No. 333-81772) relating
to our public offering of 3,450,000 Common Units (including the Underwriters'
over-allotment option to purchase 450,000 Common Units).

We filed a current report on Form 8-K dated May 1, 2003 to report our name
change to GulfTerra Energy Partners, L.P.

We filed a current report on Form 8-K dated May 14, 2003 to report that our
general partner has been reorganized into GulfTerra Energy Company, L.L.C. and
various amendments to our limited partnership agreement.

49

SIGNATURES

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

GULFTERRA ENERGY PARTNERS, L.P.

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

Date: May 15, 2003 By: /s/ KEITH B. FORMAN
------------------------------------
Keith B. Forman
Vice President and Chief Financial
Officer
(Principal Financial Officer)

Date: May 15, 2003 By: /s/ KATHY A. WELCH
------------------------------------
Kathy A. Welch
Vice President and Controller
(Principal Accounting Officer)

50

CERTIFICATION

I, Robert G. Phillips, certify that:

1. I have reviewed this quarterly report on Form 10-Q of GulfTerra Energy
Partners, L.P.;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and

(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: May 15, 2003

/s/ ROBERT G. PHILLIPS
--------------------------------------
Robert G. Phillips
Chief Executive Officer
GulfTerra Energy Company, L.L.C.
general partner of GulfTerra Energy
Partners, L.P.

51

CERTIFICATION

I, Keith B. Forman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of GulfTerra Energy
Partners, L.P.;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and

(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: May 15, 2003

/s/ KEITH B. FORMAN
--------------------------------------
Keith B. Forman
Chief Financial Officer
GulfTerra Energy Company, L.L.C.
general partner of GulfTerra Energy
Partners, L.P.

52

INDEX TO EXHIBITS