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
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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.

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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:

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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