EL PASO ENERGY PARTNERS LP - 10-Q Quarterly Report

Back to GetFilings.com

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

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

----------

FORM 10-Q

(MARK ONE)

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002

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

EL PASO 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 77049
(Address of Principal Executive Offices) (Zip Code)

Registrant's Telephone Number, Including Area Code: (832) 676-2600

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 [ ]

The registrant had 44,030,314 common units outstanding as of November 8,
2002.

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

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO ENERGY PARTNERS, L.P.

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

See accompanying notes.

1

EL PASO ENERGY PARTNERS, L.P.

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

See accompanying notes.

2

EL PASO ENERGY PARTNERS, L.P.

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

See accompanying notes.

3

EL PASO 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 LOSS

See accompanying notes.

4

EL PASO ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

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 current report on Form
8-K/A dated July 19, 2002, which includes a summary of our significant
accounting policies and other disclosures. The financial statements as of
September 30, 2002, and for the quarters and nine months ended September 30,
2002 and 2001, are unaudited. We derived the balance sheet as of December 31,
2001, from the audited balance sheet filed in our current report on Form 8-K/A
dated July 19, 2002. 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 our businesses, information for interim periods
may not indicate 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. Additionally, we have reflected the results of operations
from our Prince assets disposition as discontinued operations for all periods
presented. See Note 3 for a further discussion of the Prince Assets Disposition.

Our accounting policies are consistent with those discussed in our Form
8-K/A dated July 19, 2002, except as discussed below.

Revenues and Cost of Natural Gas

Prior to our April 2002 acquisition of the Texas and New Mexico assets,
which we refer to as the EPN Holding assets, our cost of natural gas consisted
primarily of gas purchased at El Paso Intrastate Alabama for resale. As a result
of our acquisition of the EPN Holding assets, we are now incurring additional
cost of natural gas related to system imbalances and for the purchase of natural
gas as part of our producer services activities. As a convenience for our
producers, we may purchase natural gas from them at the wellhead at an index
price less an amount that compensates us for our gathering services. We then
sell this gas into the open market at points on our system at the same index
price. We reflect these sales in our revenues and the related purchases as cost
of natural gas.

Goodwill and Other Intangible Assets

On January 1, 2002, we adopted Statement of Financial Accounting Standards
(SFAS) No. 142, Goodwill and Other Intangible Assets. Our adoption of this
standard did not have a material effect on our financial statements.

Asset Impairments

On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS No. 144 changed the accounting
requirements related to when an asset qualifies as held for sale or as a
discontinued operation and the way in which we evaluate assets for impairment.
It also changes the accounting for discontinued operations such that we can no
longer accrue the estimate for future
- ---------------

As generally used in the energy industry and in this document, the following
terms have the following meanings:

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

5

operating losses but report them as they are incurred. We applied SFAS No. 144
in accounting for our Prince assets, which met all the requirements to be
treated as an asset held for sale, in April 2002. See Note 3, Prince Assets
Disposition, for further information.

2. ACQUISITIONS

Proposed San Juan Assets Acquisition

In July 2002, we entered into a letter of intent with El Paso Corporation,
the indirect parent of our general partner, to acquire for $782 million El Paso
Corporation's natural gas gathering system located in the San Juan Basin of New
Mexico, including El Paso Corporation's remaining interests in the Chaco
cryogenic natural gas processing plant; natural gas liquids (NGL) transportation
and fractionation assets located in Texas; and an oil and natural gas gathering
system located in the deeper water regions of the Gulf of Mexico, referred to
collectively as the San Juan assets. As part of this transaction, El Paso
Corporation will be required to repurchase the Chaco processing plant from us
for $77 million in October 2021, and at that time, we will have the right to
lease the plant from El Paso Corporation for a period of ten years with the
option to renew the lease annually thereafter. The purchase price of $782
million is subject to adjustments primarily for working capital and capital
expenditures.

The parties' obligations under the letter of intent are subject to the
satisfaction of specified conditions, including negotiating and executing
definitive agreements, obtaining other third-party approvals and consents,
obtaining satisfactory results from ongoing due diligence and obtaining
financing satisfactory to us. We expect to close the transaction in the fourth
quarter of 2002. Ultimately, we expect to finance our acquisition of the San
Juan assets through long-term debt and equity.

The equity component of the proposed acquisition contemplates us issuing to
El Paso Corporation up to $350 million of our Series C units, a new class of our
limited partner interests. The potential $350 million Series C issuance will be
reduced by the proceeds from any common unit issuance we may consummate before
the closing of the San Juan assets acquisition.

The Series C units will be similar to our existing common units, except
that the Series C units will be non-voting. After April 30, 2003, El Paso
Corporation (or its subsidiaries, as applicable) will have the right to cause us
to propose a vote of our common unitholders as to whether the Series C units
should be converted into common units. If our common unitholders approve the
conversion, then each Series C unit will convert into a common unit. If our
common unitholders do not approve the conversion within 120 days after El Paso
Corporation requests the vote, then the distribution rate for the Series C units
will increase to 105 percent of the common unit distribution rate. Thereafter,
the Series C unit distribution rate would increase on April 30, 2004 to 110
percent of the common unit distribution rate and on April 30, 2005 to 115
percent of the common unit distribution rate. The issue price for the Series C
units will be the greater of $32 per unit or the average market price of a
common unit for the five trading days ending on the business day immediately
preceding the closing date. If the average market price is less than $27, the
San Juan acquisition may be delayed, terminated or renegotiated.

The remaining balance of the purchase price will be paid in cash. We expect
to fund this portion of the purchase price with a $282 million senior secured
acquisition term loan and other long-term debt of $150 million.

In accordance with our procedures for evaluating and valuing material
acquisitions with El Paso Corporation, our Special Conflicts Committee engaged
an independent financial advisor and obtained two separate fairness opinions for
the acquisition of the San Juan assets and the issuance of the Series C units.
The opinions we received stated the transaction and the issuance were both fair
to us and our unitholders.

6

EPN Holding Assets

In April 2002, EPN Holding Company, L.P., our wholly-owned subsidiary,
acquired from El Paso Corporation, midstream assets located in Texas and New
Mexico. The acquired assets, which we refer to as the EPN Holding assets,
include:

- the EPGT Texas intrastate pipeline system;

- the Waha natural gas gathering and treating system located in the Permian
Basin region of Texas and New Mexico;

- the Carlsbad natural gas gathering system located in the Permian Basin
region of New Mexico;

- an approximate 42.3 percent non-operating interest in the Indian Basin
natural gas processing and treating facility located in southeastern New
Mexico;

- a 50 percent undivided interest in the Channel natural gas pipeline
system located along the Gulf coast of Texas;

- the TPC Offshore natural gas pipeline system located off the Gulf coast
of Texas; and

- a leased interest in the Wilson natural gas storage facility located in
Wharton County, Texas.

The $750 million purchase price was adjusted for the assumption of $15
million of working capital related to natural gas imbalances. The net
consideration of $735 million for the EPN Holding assets was comprised of the
following:

- $420 million of cash;

- $119 million of assumed short-term indebtedness payable to El Paso
Corporation, which has been repaid;

- $6 million in common units; and

- $190 million in assets, comprised of our Prince tension leg platform
(TLP) and our nine percent Prince overriding royalty interest.

To finance substantially all of the cash consideration related to this
acquisition, EPN Holding entered into a limited recourse credit agreement with a
syndicate of commercial banks. See Note 6 for a further discussion of the EPN
Holding acquisition facility.

We accounted for this acquisition as a purchase. Accordingly, an allocation
of the purchase price has been assigned to the assets and liabilities acquired
based upon their estimated fair value as of the acquisition date. All of the
purchase price has been allocated to the EPN Holding net assets acquired. Such
allocation is based on our internal evaluation of the assets. An independent
appraisal of the fair value of the assets acquired is expected to be completed
by the end of 2002. That appraisal will be the basis of the final allocation of
the purchase price assigned to the assets and liabilities acquired.

The following selected unaudited pro forma information represents our
consolidated results of operations on a pro forma basis as if we acquired the
EPN Holding assets on January 1, 2001:

The selected pro forma information for the quarter ended September 30, 2002
is not provided because the results of operations for the EPN Holding assets are
included in the actual results of operations for the period. The selected pro
forma information does not necessarily represent what our results of operations
actually

7

would have been if these transactions and events had in fact occurred when
assumed and are not necessarily representative of our results of operations for
any future period.

Hattiesburg Propane Storage

In January 2002, we acquired a 3.3 million barrel propane storage business
and leaching operation located in Hattiesburg, Mississippi from Suburban Propane
Partners, L.P for approximately $10 million. As part of the transaction, we
entered into a long-term propane storage agreement with Suburban Propane
Partners for a portion of the acquired propane storage capacity.

Big Thicket

In August 2002, we acquired the Big Thicket assets, which consist of the
Silsbee compressor station and the Big Thicket gathering system, for
approximately $11 million from BP America Production Company. The Silsbee
compressor station acts as a booster station for a web of area gas gathering
lines. The facility has four 1,200 horsepower gas compressors that boost low
pressure field gas from 45 to 950 pounds of plant inlet pressure. The Big
Thicket gathering system is comprised of approximately 150 miles of 4 to 10 inch
diameter pipe with throughput of approximately 22 MMcf/d.

3. PRINCE ASSETS DISPOSITION

In connection with our April 2002 acquisition of the EPN Holding assets
from El Paso Corporation, we sold our Prince tension leg platform (TLP) and our
nine percent overriding royalty interest in the Prince Field to subsidiaries of
El Paso Corporation. The results of operations for these assets have been
accounted for as discontinued operations and have been excluded from continuing
operations for all periods in our statements of income. Accordingly, the segment
results in Note 9 reflect neither the results of operations for the Prince
assets nor the related net assets held for sale. The Prince TLP was previously
included in the Platform services segment and the related royalty interest was
included in Other. Included in income from discontinued operations for the nine
months ended September 30, 2002, were revenues of $6.7 million attributable to
these disposed assets. We did not recognize any revenues related to the Prince
assets during the quarter ended September 30, 2002, as these assets were sold in
April 2002. Included in income from discontinued operations for the quarter and
nine months ended September 30, 2001, was revenues of $1.9 million.

The assets and liabilities related to the Prince assets disposition consist
of the following:

In April 2002, we sold the Prince assets for $190 million and recognized a
gain on the sale of $0.4 million during 2002. In conjunction with this
transaction, we repaid the related outstanding $95 million principal balance
under our Argo term loan.

8

4. PARTNERS' CAPITAL

Cash distributions

The following table reflects our per unit cash distributions to our common
unitholders and the total distributions paid to our common unitholders and
general partner during the nine months ended September 30, 2002:

In October 2002, we declared a cash distribution of $0.675 per common unit,
$29.7 million in aggregate, for the quarter ended September 30, 2002, which we
will pay on November 15, 2002, to holders of record as of October 31, 2002. In
addition, we will pay distributions to our general partner of $12.0 million in
respect of its general partner interest. At the current distribution rates, our
general partner receives approximately 29 percent of our total cash
distributions for its role as our general partner.

Public offering of common units

In April 2002, we issued 4,083,938 common units, which included 1,083,938
common units purchased by our general partner pursuant to its anti-dilution
right under our partnership agreement, at the public offering price of $37.86
per unit. We used the net cash proceeds of approximately $149 million to reduce
indebtedness under EPN Holding's acquisition facility. Also in April 2002, we
issued approximately 159,000 common units at the then-current market price of
$37.74 per unit to a subsidiary of El Paso Corporation as partial consideration
for our acquisition of the EPN Holding assets. In addition, our general partner
contributed approximately $0.6 million in cash to us in April 2002 in order to
maintain its one percent capital account balance.

Other

In the second quarter of 2002, under the 1998 Unit Option Plan for
Non-Employee Directors, we issued 5,429 restricted units with a grant price of
$32.23 per unit. We have reflected the issuance of the restricted units as
deferred compensation and as an increase in common units. This deferred
compensation was approximately $175 thousand and 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, which we have estimated to be one year. The
unamortized amount of our total deferred compensation as of September 30, 2002,
was approximately $1.5 million.

9

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment consisted of the following:

6. DEBT AND OTHER CREDIT FACILITIES

Shelf registration

In February 2002, our shelf registration statement, as filed with the
Securities and Exchange Commission covering up to $1 billion of securities
representing limited partnership interests, became effective.

Credit Facility

As of September 30, 2002, we had $569 million outstanding with an average
interest rate of 4.46% under our $600 million credit facility with the total
unused amount available. The credit facility matures in May 2004, is guaranteed
by all of our subsidiaries except for our unrestricted subsidiaries and El Paso
Energy Partners Finance Corporation, and is collateralized by substantially all
of our assets (excluding our unrestricted subsidiaries), and our general
partner's general and administrative services agreement. The credit facility,
together with the EPN Holding acquisition facility, contains covenants that
include restrictions on our and our subsidiaries' ability to incur additional
indebtedness or liens, sell assets, make loans or investments, acquire or be
acquired by other companies and amend some of our contracts, as well as
requiring maintenance of certain financial ratios. As of September 30, 2002, we
are not aware of anything that causes us not to be in compliance with the
financial ratios and covenants contained in our credit facilities.

In October 2002, we amended our $600 million credit facility and the EPN
Holding acquisition facility in connection with our issuance of the senior
secured term loan. The modifications included, among other things, (1) entering
into a new $160 million senior secured term loan maturing in 2007; (2)
designating our credit facility, the EPN Holding acquisition facility, and the
senior secured term loan as "senior secured" indebtedness which is
cross-collateralized on an equal basis with all of the collateral currently
pledged under our credit facility and the EPN Holding acquisition facility; (3)
aligning, effectively, the covenants in our credit facility and the EPN Holding
acquisition facility, including eliminating the restrictions for distributing
cash out of EPN Holding; and (4) terminating the $25 million revolving credit
facility that was formerly part of the EPN Holding acquisition facility. Our new
senior secured term loan and the EPN Holding acquisition facility are discussed
below. We used the $160 million proceeds from the senior secured term loan to
temporarily reduce indebtedness under our $600 million credit facility.

Senior Secured Term Loan

In October 2002, in connection with the amendment of our credit facilities
discussed above, we obtained a $160 million senior secured term loan with a
syndicate of lenders. We may elect that all or a portion of the senior secured
term loan bear interest at either 2.25% plus a variable base rate (equal to the
greater of the prime rate as determined by JP Morgan, the federal funds rate
plus 0.5% or the CD rate as determined by JP Morgan plus 1%); or LIBOR plus
3.5%. We may, at our option, make prepayments in amounts not less

10

than $5 million. However, prepayments we make during the first year of the
senior secured term loan require payment of a premium equal to one percent of
the prepayment amount. The senior secured term loan is payable in semi-annual
installments equal to one percent of the aggregate principal amount of the
senior secured term loan for the first nine installments and the remaining
balance at maturity in October 2007. The senior secured term loan is guaranteed
by us and all of our material subsidiaries; and is cross-collateralized with our
credit facility and our EPN Holding acquisition facility, by our general and
administrative agreement, substantially all of our assets and our general
partner's one percent general partner interest in us.

Limited Recourse Financing

EPN Holding acquisition facility -- In connection with our acquisition of
the EPN Holding assets from El Paso Corporation in April 2002, EPN Holding
entered into a $560 million limited recourse acquisition facility with a group
of commercial banks. The acquisition facility provided a term loan of $535
million to finance the acquisition of the EPN Holding assets, and a revolving
credit facility of up to $25 million to finance EPN Holding's working capital.
EPN Holding's obligations under the acquisition facility are guaranteed by all
of our material subsidiaries and equity interests. At the time of its
acquisition, EPN Holding borrowed $535 million ($531 million, net of issuance
costs) under this term loan and had $25 million available under the revolving
credit facility. The EPN Holding term loan matures in April 2005. We used net
proceeds of approximately $149 million from our April 2002 common unit offering,
$0.6 million contributed by our general partner to maintain its one percent
capital account balance and $225 million of the proceeds from our May 2002
offering of 8.5% senior subordinated notes to reduce indebtedness under the term
loan. As of September 30, 2002, the outstanding balance under the term loan was
$160 million bearing interest at a rate of 4.32% and there were no amounts
outstanding under the acquisition facility revolving credit facility.

In October 2002, as a result of amending our $600 million credit facility
discussed above, the EPN Holding acquisition facility covenants were modified
and the related $25 million revolving credit facility was terminated.

Argo term loan -- This loan with a balance of $95 million, including
current maturities, at December 31, 2001, was repaid in full in April 2002, in
connection with the EPN Holding asset acquisition.

Senior Subordinated Notes

In May 2002, we issued $230 million in aggregate principal amount of 8.5%
Senior Subordinated Notes due June 2011. The Senior Subordinated Notes were
issued for $234.6 million (proceeds of approximately $230 million, net of
issuance costs). We used proceeds of $225 million to reduce indebtedness under
our EPN Holding acquisition facility and the remainder for general partnership
purposes. In August 2002, we filed a registration statement for an offer to
exchange these notes for registered debt securities with identical terms. The
registration statement is currently under review by the SEC.

Other credit facilities

Poseidon Oil Pipeline Company, L.L.C., an unconsolidated affiliate, is
party to a $185 million credit agreement under which it has outstanding
obligations 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 interest rate at 4.99% through January 2004 on $75 million
of the $150 million outstanding on its credit facility. As of September 30,
2002, the remaining $75 million was at an average floating interest rate of
3.38%.

In August 2002, Deepwater Gateway, our joint venture that owns the Marco
Polo TLP, obtained a $155 million project loan at a variable interest rate from
a group of commercial lenders to finance a substantial portion of the cost to
construct the Marco Polo TLP and related facilities. Upon completion of the
construction, the project loan will convert into a term loan, subject to the
terms of the loan agreement. The loan is collateralized by substantially all of
Deepwater Gateway's assets. If Deepwater Gateway defaults on its payment
obligations under the loan, we would be required to pay to the lenders all
distributions we or any of

11

our subsidiaries had received from Deepwater Gateway up to $22.5 million. As of
September 30, 2002, Deepwater Gateway had no amounts outstanding under the
project loan and had not paid us or any of our subsidiaries any distributions.
If Deepwater Gateway had amounts outstanding as of September 30, 2002, the
average interest rate would have been 3.56%.

7. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, we, along with several subsidiaries of El Paso
Corporation, 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.

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 gas working
interest owners and 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 has been filed and we have
filed our response.

Our Argo L.L.C. subsidiary received a claim from its contractor related to
our recently completed Prince TLP. The contractor received a request for
additional payments from its subcontractor as a result of variation orders and
is seeking to pass these costs along to Argo. After negotiations, the
contractor, the subcontractor and Argo agreed upon a settlement in July 2002.
This settlement did not have a material adverse effect on our financial
position, results of operations or cash flow.

Under the terms of our agreement with El Paso Corporation pursuant to which
we acquired the EPN Holding assets, subsidiaries of El Paso Corporation have
agreed to indemnify us against all obligations related to existing legal matters
at the acquisition date, including the legal matters involving Leapartners,
L.P., City of Edinburg, Houston Pipe Line Company LP and City of Corpus Christi
discussed below.

During 2000, Leapartners, L.P. filed a suit against El Paso Field Services
and others in the District Court of Loving County, Texas, alleging a breach of
contract to gather and process gas in areas of western Texas related to an asset
now owned by EPN 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 are set for
November 2002.

Also, EPGT Texas Pipeline L.P., now owned by EPN Holding, is involved in
litigation with the City of Edinburg concerning the City's claim that EPGT 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 EPGT Texas and is
now owned by Southern Union Gas Company. An adverse judgment against Southern
Union and EPGT Texas was rendered in Hidalgo County State District court in
December 1998 and found a breach of

12

contract, and held both EPGT 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 EPGT
Texas and Southern Union's entities that were not parties to the contract with
the City. EPGT Texas has appealed this case to the Texas Supreme Court seeking
reversal of the judgment rendered against EPGT Texas. The City seeks a remand to
the trial court of its claim of tortious interference against EPGT Texas. Briefs
have been filed and oral arguments are set for November 2002.

In December 2000, a 30-inch natural gas pipeline jointly owned by El Paso
Energy Intrastate, now owned by EPN Holding, and Houston Pipe Line Company LP
ruptured in Mont Belvieu, Texas, near Baytown, resulting in substantial property
damage and minor physical injury. El Paso Energy Intrastate is the operator of
the pipeline. In December 2000 a lawsuit was 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, El Paso Energy 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). The discovery phase of the lawsuit is proceeding and trial
is expected in early 2003.

The City of Corpus Christi, Texas ("City") is alleging that EPGT Texas and
various Coastal entities owe it monies for past obligations under City
ordinances that propose to tax EPGT 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 EPGT Texas pipe at issue has been using the
rights-of-way since the 1960's. In addition, the City demands that EPGT Texas
agree to a going-forward consent agreement in order for EPGT Texas pipe and
Coastal 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 September 30, 2002, 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.

Environmental

Each of our operating segments is subject to extensive federal, state, and
local laws and regulations governing environmental quality and pollution
control. These laws and regulations are applicable to each segment and require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of September
30, 2002, 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. In addition, 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. 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

13

environment resulting from our current or past operations, could result in
substantial costs and liabilities in the future. 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.

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, additional comments were filed by us. 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 entities. 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 reviewing whether or
not a pipeline's "recourse rate" (its cost of service based rate) continues to
safeguard against a pipeline exercising market power, as well as other issues
related to negotiated rate programs.

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. 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 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.

14

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.

Other Regulatory Matters. Our HIOS system is also 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 are obligated to file a new rate case for our HIOS system no later than
December 31, 2002.

In June 2002, Petal Gas Storage 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 December 1999, EPGT 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 EPGT Texas' proposed rates. It also ordered
refunds to customers for the difference, if any, between the originally proposed
levels and the revised rates ordered by the FERC. 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. We believe the amount of any rate refund would be minimal
since, as provided for in our tariff, we were not charging our customers at the
maximum rate. In July 2002, EPGT Texas requested rehearing on certain issues
raised by the FERC's order, including the ordered changes to rate design and
depreciation rates, and the requirement to separately state a gathering rate.
Falcon Gas Storage also requested late intervention and rehearing of the order.
Falcon asserts that EPGT Texas' imbalance penalties and terms of service
preclude third parties from offering imbalance management services. EPGT Texas'
request for rehearing has been granted and 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.

Other Matters

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

8. ACCOUNTING FOR HEDGING ACTIVITIES

A majority of our commodity purchases and sales, which relate to sales of
oil and natural gas associated with our production operations, purchases and
sales of natural gas associated with 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 relating to gathering activities for changes in natural
gas prices in the San Juan Basin in anticipation of our proposed acquisition of
the San Juan assets. The derivative is a financial swap on 30,000 MMBtu per day
15

whereby we receive a fixed price of $3.525 per MMBtu and pay a floating price
based on the San Juan index. We are accounting for this derivative under
mark-to-market accounting since it does not qualify for hedge accounting under
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As
of September 30, 2002, the fair value of this derivative was a $1.0 million
liability and we recognized this $1.0 million loss in the margin of our Natural
gas pipelines and plants segment. Once the proposed acquisition of the San Juan
assets is completed, we expect to designate this derivative as a cash flow hedge
under SFAS 133.

At September 30, 2002, 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 2001 and 2002 to offset the risk of increasing natural
gas prices. As of September 30, 2002, the fair value of these cash flow hedges
was an asset of approximately $49 thousand. For the nine months ended September
30, 2002, the majority of these cash flow hedges expired and we reclassified a
loss of $1.4 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 nine months.

Starting in April 2002, in connection with our EPN Holding acquisition, we
have swaps in place for our interest in the Indian Basin processing plant to
hedge the price received for the sale of natural gas liquids. As of September
30, 2002, the fair value of these cash flow hedges was a $126 thousand liability
resulting in an unrealized loss of $126 thousand. We do not expect any
ineffectiveness in our hedging relationship since all sale prices are based on
the same index as the hedge transaction. We estimate the entire amount will be
reclassified from accumulated other comprehensive income to earnings over the
next three months.

In January 2002, Poseidon entered into a two-year interest rate swap
agreement to fix the interest rate on $75 million of its $150 million variable
rate revolving credit facility at 4.99% over the life of the swap. As of
September 30, 2002, the fair value of its interest rate swap was a liability of
$1.6 million resulting in accumulated other comprehensive loss of $1.6 million.
We included our 36 percent share of this liability of $0.6 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 15 months. Additionally, we have recognized in
income our 36 percent share of Poseidon's realized loss of $0.9 million for the
nine months ended September 30, 2002, or $0.3 million, through our earnings from
unconsolidated affiliates.

Our counterparties for EPIA and Indian Basin hedging activities are El Paso
Merchant Energy and El Paso Field Services, affiliates of our general partner.
We do not require collateral and do not anticipate non-performance by our
counterparties. The counterparty for Poseidon's hedging activity is Credit
Lyonnais. Poseidon does not require collateral and does not anticipate
non-performance by the counterparty. The counterparty for our San Juan hedging
activity is J. Aron and Company, a subsidiary of Goldman Sachs. We do not
require collateral and do not anticipate non-performance by our counterparty.

9. SEGMENT INFORMATION

In light of our expectation of acquiring additional natural gas pipeline
and processing assets, effective January 1, 2002, we revised and renamed our
business segments to reflect the change in composition of our operations as
discussed below. 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.

16

In October 2001, we acquired the Chaco processing plant and reflected the
operations of this asset in our Oil and NGL logistics segment. With the change
in our segments, we moved the Chaco processing plant to our Natural gas
pipelines and plants segment. 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. Beginning in 2002, operations from our oil and
natural gas production activities are reflected in Other.

We have restated the prior periods, to the extent practicable, in order to
conform to our current business segment presentation. The restated results of
operations for the quarter and nine months ended September 30, 2001, are not
necessarily indicative of the results which would have been achieved had the
revised business structure been in effect during the period.

Each of our segments are business units that offer different services and
products. They are managed separately, as each requires different technology and
marketing strategies. We measure segment performance using performance cash
flows, or an asset's ability to generate cash flow. Performance cash flows are
used as a supplemental financial measurement in the evaluation of our businesses
and should not be considered as an alternative to net income as an indicator of
our operating performance or as an alternative to cash flows from operating
activities as a measure of liquidity. Performance cash flows may not be a
comparable measurement among different companies. Following are results as of
and for the periods ended September 30:

QUARTER ENDED SEPTEMBER 30, 2002

QUARTER ENDED SEPTEMBER 30, 2001

- ----------

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

17

NINE MONTHS ENDED SEPTEMBER 30, 2002

NINE MONTHS ENDED SEPTEMBER 30, 2001

- ----------

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

18

RECONCILIATION OF PERFORMANCE CASH FLOWS BY SEGMENT

- ---------------
(1) We finance our activities and evaluate our minority interest at the
consolidated level and therefore we do not allocate interest and debt
expense among our segments.

(2) Performance cash flows (or Adjusted EBITDA) is determined by taking EBIT and
adding or subtracting, as appropriate, cash distributions from
unconsolidated affiliates; depreciation, depletion and amortization;
earnings from unconsolidated affiliates; gains and losses on asset sales;
and other nonrecurring items.

20

10. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We hold investments in various affiliates which we account for using the
equity method of accounting. In October 2001, we acquired the remaining 50
percent of Deepwater Holdings, L.L.C. that we did not already own. Following
this transaction, Deepwater Holdings has been consolidated in our financial
statements from the acquisition date. Summarized financial information for these
investments are as follows:

NINE MONTHS ENDED SEPTEMBER 30, 2002
(IN THOUSANDS)

NINE MONTHS ENDED SEPTEMBER 30, 2001
(IN THOUSANDS)

- ----------

(1) We recorded adjustments primarily for differences from estimated year end
earnings reported in our Annual Report on Form 10-K and actual earnings
reported in the audited annual reports of our unconsolidated affiliates. For
the nine months ended September 30, 2001, we recorded an additional
adjustment relating to the sale of Stingray Pipeline Company, U-T Offshore
System (UTOS) and West Cameron. The loss on these sales was not allocated
proportionately with Deepwater Holdings' ownership percentages because the
capital contributed by us was a larger amount of capital at the formation
and therefore we were allocated a larger portion of the loss. Our total
share of the loss relating to these sales was approximately $14 million.

(2) Divested Investments includes Manta Ray Offshore Gathering Company, L.L.C.
and Nautilus Pipeline Company, L.L.C. In January 2001, we sold our 25.67%
interest in Manta Ray Offshore and our 25.67% interest in Nautilus.

21

Deepwater Gateway/Marco Polo Project

In June 2002, we formed Deepwater Gateway, L.L.C., a 50/50 joint venture
with Cal Dive International Inc., to construct and install the Marco Polo TLP.
The total cost of the project is estimated to be $206 million or approximately
$103 million for our share. As of September 30, 2002, we have contributed $27
million to Deepwater Gateway.

Arizona Gas Storage, L.L.C./Copper Eagle Project

In June 2002, we acquired El Paso Corporation's effective 30 percent
interest in a natural gas storage facility development project located near
Phoenix, Arizona.

11. RELATED PARTY TRANSACTIONS

Our transactions with related parties and affiliates are as follows:

For the quarters ended September 30, 2002 and 2001, revenues received from
related parties consisted of approximately 45% and 35% of our total revenue. For
the nine months ended September 30, 2002 and 2001, revenues received from
related parties consisted of approximately 43% and 26% of our total revenue.

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 current report on Form 8-K/A dated July 19, 2002.

22

Revenues received from related parties

EPN Holding Assets. Our revenues from related parties increased in 2002 as
a result of our EPN Holding transaction in which we acquired gathering,
transportation and processing contracts with affiliates of our general partner.
For the quarter and nine months ended September 30, 2002, we received $21.8
million and $46.1 million from El Paso Merchant Energy North America Company,
$10.2 million and $19.6 million from El Paso Field Services and $1.4 million and
$2.8 million from El Paso Production Company.

Expenses paid to related parties

Cost of natural gas. Our cost of natural gas paid to related parties
increased in 2002 as a result of our EPN Holding transaction in which we
acquired contracts with affiliates of our general partner. For the quarter and
nine months ended September 30, 2002, we had natural gas imbalance settlement
expenses of $0.1 million and $0.3 million from Tennessee Gas Pipeline Company
and $0.1 million for the nine months ended September 30, 2002 from El Paso
Merchant Energy North America Company.

Operating expenses. Our operating expense paid to related parties increased
in 2002 as a result of our EPN Holding transaction in which we acquired
operating agreements with El Paso Field Services. For the quarter and nine
months ended September 30, 2002, we had operating expenses of $6.3 million and
$11.4 million.

Under a general and administrative services agreement between subsidiaries
of El Paso Corporation and us, a fee of approximately $0.8 million per month was
charged to our general partner, and accordingly, to us, which is intended to
approximate the amount of resources allocated by El Paso Corporation and its
affiliates in providing various operational, financial, accounting and
administrative services on behalf of our general partner and us. In April 2002,
in connection with our acquisition of EPN Holding assets, our general and
administrative services agreement was extended to December 31, 2005, and the fee
increased to approximately $1.6 million per month. We believe this fee
approximates the actual costs incurred.

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 7, Commitments and
Contingencies, Legal Proceedings. Some of our agreements obligate certain
indirect subsidiaries of El Paso Corporation to pay for capital costs related to
maintaining assets which were acquired by us, if such costs exceed negotiated
thresholds. We do not believe these thresholds will be exceeded. We have made no
such claims for reimbursement to date and none are contemplated to be made at
this time.

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 facilities owned by others which are connected to their
pipelines. We have, or plan to 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, Red Hawk and Medusa discoveries, payable over the
next eighteen months.

23

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

- ----------

(1) We sold our interest in Manta Ray Offshore in January 2001 in connection
with El Paso Corporation's acquisition of The Coastal Corporation.

(2) In January 2001, Deepwater Holdings sold its Stingray and West Cameron
subsidiaries. In April 2001, Deepwater Holdings sold its UTOS subsidiary. In
October 2001, we acquired the remaining 50 percent of Deepwater Holdings,
and as a result of this transaction, Deepwater Holdings is consolidated in
our financial statements from the acquisition date and our agreement with
Deepwater Holdings terminated.

24

At September 30, 2002, and December 31, 2001, our accounts receivable due
from related parties was $46.7 million and $23.0 million. At September 30, 2002
and December 31, 2001, our accounts payable due to related parties was $27.6
million and $10.1 million.

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 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:

25

12. GUARANTOR FINANCIAL INFORMATION

On May 1, 2001, we purchased our general partner's 1.01 percent
non-managing interest owned in twelve of our subsidiaries for $8 million. As a
result of this acquisition, all of our subsidiaries, but not our equity
investees, are wholly owned by us. As of September 30, 2002, our revolving
credit facility is guaranteed by each of our subsidiaries (excluding our EPN
Holding subsidiaries) and is collateralized by our general and administrative
agreement, substantially all of our assets, and our general partner's one
percent general partner interest. In addition, all of our senior subordinated
notes are jointly, severably, fully and unconditionally guaranteed by all of our
subsidiaries except EPN Holding's subsidiaries. As of September 30, 2002, the
EPN Holding acquisition facility is guaranteed by all of EPN Holding's
subsidiaries and by EPN Holding I, L.P. and EPN GP Holding L.L.C., our
unrestricted subsidiaries that own the equity interests in EPN Holding, and is
collateralized by substantially all of the assets of EPN Holding and the
guarantors. In October 2002, we rearranged our credit facilities and entered
into a $160 million senior secured term loan. As a result of that rearrangement
our credit facility, the EPN Holding acquisition facility and the senior secured
term loan are all guaranteed by all of our material subsidiaries. We are
providing the following condensed consolidating financial information of us (as
the Issuer) and our subsidiaries as if our current organizational structure were
in place for all periods presented. The consolidating eliminations column on our
balance sheets eliminate our investment in consolidated subsidiaries,
intercompany payables and receivables and other transactions between
subsidiaries.

Non-guarantor subsidiaries as of and for the quarter and nine months ended
September 30, 2002, consisted of our EPN Holding subsidiaries, which own the EPN
Holding assets and the equity interests in EPN Holding, and our subsidiary that
owns our interest in the Copper Eagle project. Non-guarantor subsidiaries for
all other periods 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 SEPTEMBER 30, 2002

26

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE QUARTER ENDED SEPTEMBER 30, 2001

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

27

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001

28

CONDENSED CONSOLIDATING BALANCE SHEETS
SEPTEMBER 30, 2002

29

CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2001

30

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

31

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001

32

13. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

We continually monitor the activities of the various rule makers involved
in developing general accepted accounting principles for use in the United
States. At this time, there are several new accounting pronouncements that have
recently been issued, but are not yet adopted, which will impact our accounting
when these rules become effective. The new rules not yet adopted that will have
an impact on our accounting policies are discussed below.

Accounting for Asset Retirement Obligations

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This statement requires
companies to record a liability for the estimated retirement and removal costs
of assets used in their business. The liability is discounted to its present
value, and the related asset value is increased by the amount of the resulting
liability. Over the life of the asset, the liability will be accreted to its
future value and eventually extinguished when the asset is taken out of service.
Capitalized retirement and removal costs will be depreciated over the useful
life of the related asset. The provisions of this statement are effective for
fiscal years beginning after June 15, 2002. We are currently evaluating the
effects of this pronouncement.

Reporting Gains and Losses from the Early Extinguishment of Debt

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement addresses how to report gains or losses resulting
from the early extinguishment of debt. Previously, any gains or losses were
reported as an extraordinary item. Upon adoption of SFAS No. 145, an entity will
be required to evaluate whether the debt extinguishment is truly extraordinary
in nature, in accordance with Accounting Principles Board Opinion No. 30. If the
entity routinely extinguishes debt early, the gain or loss should be included in
income from continuing operations. This statement is effective for our 2003
year-end reporting.

Accounting for Costs Associated with Exit or Disposal Activities

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. Examples of costs
covered by this guidance include lease termination costs and certain employee
severance costs that are associated with a restructuring, discontinued
operation, plant closing, or other exit or disposal activity. The provisions of
this statement are effective for fiscal years beginning after December 31, 2002.
The provisions of this statement will impact any exit or disposal activities
that we initiate after January 1, 2003.

33

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, 2001, in addition to
the interim financial statements and notes presented in Item 1 of this Quarterly
Report on Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Since the fourth quarter of 2001, a number of developments in our
businesses and industry have significantly impacted our operations and
liquidity, as well as the United States debt and equity markets. Our ability to
execute our growth strategy and complete our current projects is dependent upon
our ability to access the capital necessary to fund our projects and
acquisitions. How much we actually spend will depend on our success with capital
raising efforts, including the formation of joint ventures to share costs and
risks. At this time, we believe our access to capital resources is sufficient to
meet the demands of our current and future operating growth needs. Although we
intend to make the forecasted project expenditures, we may adjust the timing and
amounts of the projected expenditures as necessary to adapt to changes in the
capital markets.

FORECASTED EXPENDITURES

Our management estimates capital expenditures based upon current
expectations; however, estimates may change due to factors out of our control,
such as weather related issues or changes in supplier prices. Further, estimates
may change as a result of decisions made at a later date, such as scope changes
or decisions to take on additional partners.

The table below depicts our estimate of expenditures on projects,
acquisitions, operating lease payments and debt repayments for the twelve month
period ending September 30, 2003. These expenditures are net of anticipated
financings, contributions in aid of construction and contributions from joint
venture partners. Actual results may vary from these projections.

CAPITAL RESOURCES

During the third quarter of 2002, the United States equity and debt markets
remained volatile due to the announcements of several SEC investigations,
corporate scandals, and business failures. With the collapse of

34

former energy giant Enron, the prospect for war with Iraq and significant
negative media coverage, the energy sector has experienced market volatility,
primarily by those companies involved in energy marketing. The flight of
investors from the equity markets to "safer havens" has prevented all but the
most stalwart of companies from tapping the debt and equity markets for raising
capital. Additionally, numerous energy companies have experienced downgrades in
their debt securities by Moody's Investors Service (Moody's) and Standard &
Poor's (S&P), two of the largest debt rating agencies, effectively reducing the
ability of many energy companies from raising operating capital from the credit
markets. Although current economic conditions are unfavorable, we expect the
economy to stabilize and improve over the next six to twelve months, which
should also produce stability in the credit and equity markets and provide for
increased access to additional sources of capital.

Despite the difficulty in the credit and equity markets, we successfully
raised $160 million through the issuance of our senior secured term loan to a
syndicate of lenders following the end of the third quarter. We continue to reap
the benefits of our solid balance sheet and operating performance as evidenced
by Moody's and S&P's recent affirmation of our credit ratings. Finally, the
continued strong operating performance of our current assets has enabled us to
increase our borrowing capacity under our financial covenants, effectively
increasing our ability to access cash for executing our operating and growth
objectives.

In October 2002, we also amended our $600 million credit facility and the
EPN Holding acquisition facility to among other things: (1) enter into the $160
million senior secured term loan discussed above; (2) designate all of the above
loans as "senior secured" indebtedness, which is cross-collateralized with all
of the collateral currently pledged under our credit facility and the EPN
Holding acquisition facility; (3) align, effectively, the covenants in our
credit facility and the EPN Holding acquisition facility; and (4) terminate the
$25 million working capital revolver that was formerly part of the EPN Holding
acquisition facility.

These credit facilities contain covenants that include restrictions on our
and our subsidiaries' ability to incur additional indebtedness or liens, sell
assets, make loans or investments, acquire or be acquired by other companies and
amend some of our contracts, as well as requiring maintenance of certain
financial ratios. As of September 30, 2002, we are not aware of anything that
causes us not be in compliance with the financial ratios and covenants contained
in our credit agreements.

We have three features contained in our debt instruments described as
ratings triggers. Two of these features provide us, rather than creditors, with
certain rights in the event that our credit ratings change to an investment
grade level. These triggers are contained in our:

- indenture governing our $480 million 8 1/2% Senior Subordinated Notes due
2011 ($230 million of which were issued in May 2002), where many
covenants will be suspended in the event we achieve an investment grade
credit rating; and

- $600 million credit facility, where we will receive a 38 to 50 basis
point reduction in our interest rate in the event we achieve an
investment grade credit rating.

Additionally, with respect to our $160 million senior secured term loan,
if, at any time, our senior, long-term unsecured debt rating (a) issued by
Standard & Poor's is less than BB+ or (b) issued by Moody's is less than Ba1, or
our senior secured debt rating issued by Moody's is less than Ba1, the interest
rate on that term loan increases by one percent. There are no other trigger
features or mechanisms in any of our debt instruments or commercial
arrangements.

DEBT REPAYMENT AND OTHER OBLIGATIONS

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

35

The following table presents the timing and amounts of our debt payment and
other obligations for the years following September 30, 2002, that we believe
could affect our liquidity (in millions):

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

(1) The senior secured term loan was funded in October 2002, as more fully
discussed in Note 6 of the financial statements included in Item 1 and in
Item 2, Management's Discussion and Analysis of Financial Condition and
Results of Operations.

SERIES B PREFERENCE UNITS

In August 2000, we issued $170 million of Series B preference units to
acquire the natural gas storage businesses of Crystal Gas Storage, Inc. These
preference units are non-voting and have rights to income allocations on a
cumulative basis, compounded semi-annually at an annual rate of 10%. We are not
obligated to pay cash distributions on these units until 2010. After September
2010, the rate will increase to 12% and preference income allocation after 2010
will be required to be paid on a current basis; accordingly, after September
2010, we will not be able to make distributions on our common units unless all
unpaid accruals occurring after September 2010 on our then-outstanding Series B
preference units have been paid. These preference units contain no mandatory
redemption obligation, but may be redeemed at our option at any time. In October
2001, we redeemed 44,608 of the Series B preference units for $50 million
liquidation value, including accrued distributions of approximately $5.4
million, bringing the total number of units outstanding to 125,392. As of
September 30, 2002, the liquidation value of the outstanding Series B preference
units was approximately $154 million.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $138.5 million for the nine
months ended September 30, 2002, compared to $89.3 million for the same period
in 2001. The increase was attributable to operating cash flows from our
acquisitions of the Chaco plant in October 2001, the remaining 50 percent
interest in Deepwater Holdings that we did not already own in October 2001, and
the EPN Holding assets in April 2002. This increase was partially offset by
lower cash distributions in 2002 from our unconsolidated affiliate, Poseidon.

CASH FROM INVESTING ACTIVITIES

Net cash used in investing activities was approximately $726.4 million for
the nine months ended September 30, 2002. Our investing activities include our
April 2002 purchase of the EPN Holding assets, our August 2002 purchase of the
Big Thicket assets and capital expenditures related to the expansion of our
Petal natural gas storage facility. Further contributing to the expenditures
were additions to investments from unconsolidated affiliates relating to our
Marco Polo project and our Copper Eagle project. These expenditures were
partially offset by proceeds of $5.5 million from the March 2002 sale of our
Buffalo Treating Facility to

36

El Paso Production Company and the April 2002 sale of our Prince TLP and nine
percent Prince overriding royalty interest to subsidiaries of El Paso
Corporation. The Prince assets sales are reflected as net cash provided by
investing activities of discontinued operations in our statement of cash flows.

CASH FROM FINANCING ACTIVITIES

Net cash provided by financing activities was approximately $597.0 million
for the nine months ended September 30, 2002. During 2002, our cash provided by
financing activities included the issuances of long-term debt and common units,
as well as borrowings under our credit facility and EPN Holding acquisition
facility. Cash used in our financing activities included repayments on our EPN
Holding acquisition facility, Argo term loan, our credit facility and other
financing obligations, as well as distributions to our partners.

RECENT DEVELOPMENTS

We often enter into transactions with El Paso Corporation and its
subsidiaries to acquire or sell assets, and have instituted specific procedures
for evaluating and valuing these transactions. Before we consider entering into
a material transaction with El Paso Corporation or any of its subsidiaries, we
determine that the proposed transaction (1) would comply with the requirements
under our indentures and credit agreements, (2) would comply with substantive
law, and (3) would be fair to us and our limited partners. In addition, our
general partner's board of directors utilizes a Special Conflicts Committee
comprised solely of independent directors. This committee:

- evaluates and, where appropriate, on occasion negotiates certain aspects
of the proposed transaction;

- engages an independent financial advisor and independent legal counsel to
assist with its evaluation of the proposed transaction; and

- determines whether to approve and recommend the proposed transaction.

We will only consummate any proposed material transaction with El Paso
Corporation if, following our evaluation of the transaction, the Special
Conflicts Committee approves and recommends the proposed transaction.

ACQUISITIONS

Proposed Acquisition of the San Juan Assets

In July 2002, we entered into a letter of intent with El Paso Corporation,
the indirect parent of our general partner, to acquire for $782 million El Paso
Corporation's natural gas gathering system located in the San Juan Basin of New
Mexico, including El Paso Corporation's remaining interests in the Chaco
cryogenic natural gas processing plant; NGL transportation and fractionation
assets located in Texas; and an oil and natural gas gathering system located in
the deeper water regions of the Gulf of Mexico, referred to collectively as the
San Juan assets. As part of this transaction, El Paso Corporation will be
required to repurchase the Chaco processing plant from us for $77 million in
October 2021, and at that time, we will have the right to lease the plant from
El Paso Corporation for a period of ten years with the option to renew the lease
annually thereafter. With the close of this transaction, the monthly fee under
our general and administrative services agreement with subsidiaries of El Paso
Corporation will increase by $1.3 million, bringing our total monthly fee to
$2.9 million. The purchase price of $782 million is subject to adjustments
primarily for working capital and capital expenditures. The following is a
description of the San Juan assets:

- The assets located in the San Juan Basin include:

- approximately 5,300 miles of natural gas gathering pipelines, known as
the San Juan gathering system, with capacity of over 1.1 Bcf/d connected
to approximately 9,500 wells producing natural gas from the San Juan
Basin located in northwest New Mexico and southwest Colorado;

- approximately 250,000 horsepower of compression;

- the 58 MMcf/d Rattlesnake CO(2) treating facility;

37

- a 50% interest in Coyote Gas Treating, L.L.C., the owner of a 250 MMcf/d
treating facility; and

- the remaining interests in the Chaco cryogenic natural gas processing
plant that we do not already own and the price risk management positions
related to this facility's operations.

- The offshore pipeline assets include:

- The Typhoon gas pipeline, a 35-mile, 20-inch natural gas pipeline
originating on the Chevron/BHP "Typhoon" platform in the Green Canyon
area of the Gulf of Mexico extending to the ANR Patterson System in
Eugene Island Block 371; and

- The Typhoon oil pipeline, a 16-mile, 12-inch oil pipeline originating on
the Chevron/BHP "Typhoon" platform and extending to a platform in Green
Canyon Block 19 with onshore access through various oil pipelines.

- The Texas NGL assets include:

- a 163-mile, 4-inch to 6-inch propane pipeline extending from Corpus
Christi to McAllen and the Hidalgo truck terminal facilities;

- the Markham butane shuttle, a 144-mile, 8-inch pipeline with capacity of
approximately 20 MBbls/d running between Corpus Christi and a leased
storage facility at Markham with capacity of approximately 3.8 MMBbls;

- a 76-mile, 6-inch pipeline with capacity of approximately 15 MBbls/d
extending from Almeda to Texas City and the Texas City terminal; and

- the Almeda fractionator, a 35 MBbls/d fractionator consisting of two
trains, one of which is currently out of service, and related leased
storage facilities of approximately 9.8 MMBbls;

- a 265-mile, 8-inch pipeline with capacity of approximately 35 MBbls/d
extending from Corpus Christi to Pasadena, which is currently out of
service.

The parties' obligations under the letter of intent are subject to the
satisfaction of specified conditions, including negotiating and executing
definitive agreements, obtaining third-party approvals and consents, obtaining
satisfactory results from ongoing due diligence and obtaining acceptable
financing satisfactory to us. We will be required to make approximately $46
million of capital expenditures to place the 8-inch pipeline back in service and
make repairs and upgrades on the Markham butane shuttle and the Almeda
fractionator. We expect to close this transaction in the fourth quarter of 2002.
Ultimately, we expect to finance our acquisition of the San Juan assets through
long-term debt and equity. Our current financing plan is outlined below (in
millions):

Series C units.............................................. $350
Senior secured acquisition term loan........................ 282
Other debt.................................................. 150
----
$782
====

The equity component of the proposed acquisition contemplates us issuing to
El Paso Corporation up to $350 million of our Series C units, a new class of our
limited partner interests. The potential $350 million Series C issuance will be
reduced by the proceeds from any common unit issuance we may consummate before
the closing of the San Juan assets acquisition.

The Series C units will be similar to our existing common units, except
that the Series C units will be non-voting. After April 30, 2003, El Paso
Corporation (or its subsidiaries, as applicable) will have the right to cause us
to propose a vote of our common unitholders as to whether the Series C units
should be converted into common units. If our common unitholders approve the
conversion, then each Series C unit will convert into a common unit. If our
common unitholders do not approve the conversion within 120 days after El Paso
Corporation requests the vote, then the distribution rate for the Series C units
will increase to 105 percent of the common unit distribution rate. Thereafter,
the Series C unit distribution rate would increase on April 30,

38

2004 to 110 percent of the common unit distribution rate and on April 30, 2005
to 115 percent of the common unit distribution rate. The issue price for the
Series C units will be the greater of $32 per unit or the average market price
of a common unit for the five trading days ending on the business day
immediately preceding the closing date. If the average market price is less than
$27, the San Juan acquisition may be delayed, terminated or renegotiated.
Assuming a price of $32 per unit, approximately 11 million units will be issued
and El Paso Corporation would own approximately 41 percent, an increase from 26
percent of the limited partners interest.

The remaining balance of the purchase price will be paid in cash. We expect
to fund this portion of the purchase price with a $282 million senior secured
acquisition term loan and other long-term debt of $150 million.

In accordance with our procedures for evaluating and valuing material
acquisitions with El Paso Corporation, our Special Conflicts Committee engaged
an independent financial advisor and obtained two separate fairness opinions for
the acquisition of the San Juan assets and the issuance of the Series C units.
The opinions we received stated the transaction and the issuance were both fair
to us and our unitholders.

EPN Holding Assets

In April 2002, EPN Holding acquired from El Paso Corporation midstream
assets located in Texas and New Mexico, including one of the largest intrastate
pipeline systems in Texas based on miles of pipe. The acquired assets include:

- the EPGT Texas intrastate pipeline system;

- the Waha natural gas gathering system and treating plant located in the
Permian Basin region of Texas;

- the Carlsbad natural gas gathering system located in the Permian Basin
region of New Mexico;

- an approximate 42.3 percent non-operating interest in the Indian Basin
natural gas processing and treating facility located in southeastern New
Mexico;

- a 50 percent undivided interest in the Channel natural gas pipeline
system located along the Gulf coast of Texas;

- the TPC Offshore natural gas pipeline system located off the Gulf coast
of Texas; and

- a leased interest in the Wilson natural gas storage facility located in
Wharton County, Texas.

The $750 million sales price was adjusted for the assumption of $15 million
of working capital related to natural gas imbalances. The net consideration of
$735 million for the EPN Holding assets was comprised of the following:

- $420 million of cash;

- $119 million of assumed short-term indebtedness payable to El Paso
Corporation, which has been repaid;

- $6 million in common units; and

- $190 million in assets, comprised of our Prince TLP and our nine percent
Prince overriding royalty interest.

To finance substantially all of the cash consideration related to this
acquisition, EPN Holding entered into a $535 million limited recourse
acquisition facility with a syndicate of commercial banks, of which $375 million
has been repaid and the remaining amount was restructured in October 2002, as
discussed in the Capital Resources section of this Item 2.

39

Hattiesburg Storage Facility

In January 2002, we acquired a 3.3 million barrel propane storage business
and leaching operation located in Hattiesburg, Mississippi from Suburban Propane
Partners, L.P. for approximately $10 million. As part of the transaction, we
entered into a long-term propane storage agreement with Suburban Propane
Partners for a portion of the acquired propane storage capacity.

Big Thicket

In August 2002, we acquired the Big Thicket assets, which consist of the
Silsbee compressor station and the Big Thicket gathering system, for
approximately $11 million from BP America Production Company. The Silsbee
compressor station acts as a booster station for a web of area gas gathering
lines. The facility has four 1,200 horsepower gas compressors that boost low
pressure field gas from 45 to 950 pounds of plant inlet pressure. The Big
Thicket gathering system is comprised of approximately 150 miles of 4 to 10 inch
diameter pipe with throughput of approximately 22 MMcf/d.

PROJECTS

Medusa Project

We are constructing the $26 million, 37-mile Medusa natural gas pipeline
extension of our Viosca Knoll gathering system with capacity to handle 160
MMcf/d of natural gas, which is expected to be in service in the first quarter
of 2003, designed and located to gather production from Murphy Exploration and
Production Company's Medusa development in the Gulf of Mexico. Murphy has
dedicated 34,560 acres of property to this pipeline for the life of the
reserves, which means that all natural gas produced from this acreage will flow
through this pipeline. As of September 30, 2002, we have spent approximately
$12.7 million related to this pipeline extension, which is currently under
construction. We expect to fund the project through borrowings on our credit
facility.

Marco Polo Project

In December 2001, we announced an agreement with Anadarko Petroleum
Corporation under which we would construct, install and own the Marco Polo TLP
with capacity to handle 100 MBbls/d of oil and 250 MMcf/d of natural gas. This
TLP, which we expect to be in service in the fourth quarter of 2003, was
designed and located to process oil and natural gas from Anadarko Petroleum
Corporation's Marco Polo Field discovery in the Gulf of Mexico. Anadarko has
dedicated 69,120 acres of property to this TLP, including the acreage underlying
their Marco Polo Field discovery, for the life of the reserves. Anadarko will
have firm capacity of 50 MBbls/d of oil and 150 MMcf/d of natural gas. The
remainder of the platform capacity will be available to Anadarko for additional
production and/or to third parties that have fields developed in the area. This
TLP will be owned by our 50 percent owned Deepwater Gateway joint venture. We
will operate the Deepwater Gateway joint venture, and the Marco Polo TLP will be
operated by Anadarko. The total cost of the project is estimated to be $206
million, or approximately $103 million for our share. As of September 30, 2002,
Deepwater Gateway has spent approximately $58.3 million on this TLP, which is
currently under construction.

In addition, we will construct and own a 36-mile, 14-inch oil pipeline and
a 75-mile, 18-inch and 20-inch natural gas pipeline to support the Marco Polo
TLP. The natural gas pipeline will gather natural gas from the Marco Polo
platform in Green Canyon Block 608 and transport to the Typhoon natural gas
pipeline in Green Canyon Block 237 with a maximum capacity of 400 MMcf/d. The
oil pipeline will gather oil from the Marco Polo platform to our Allegheny
pipeline in Green Canyon Block 164 with a maximum capacity of 100 MBbls/d. These
pipelines are expected to be completed and placed in service in the first
quarter of 2004, and are expected to cost $79 million to construct. As of
September 30, 2002, we have spent approximately $1.3 million on these pipelines,
which are in the development stage.

In August 2002, Deepwater Gateway, our joint venture that owns the Marco
Polo TLP, obtained a $155 million project loan at a variable interest rate from
a group of commercial lenders to finance a substantial

40

portion of the cost to construct the Marco Polo TLP and related facilities. Upon
completion of the construction, the project loan will convert into a term loan,
subject to the terms of the loan agreement. The loan is collateralized by
substantially all of Deepwater Gateway's assets. If Deepwater Gateway defaults
on its payment obligations under the loan, we would be required to pay to the
lenders all distributions we or any of our subsidiaries had received from
Deepwater Gateway up to $22.5 million. As of September 30, 2002, Deepwater
Gateway had no amounts outstanding under the project loan and had not paid us or
any of our subsidiaries any distributions.

Cameron Highway

In February 2002, we announced that we will build and operate the $458
million, 390-mile Cameron Highway Oil Pipeline with capacity of 500 MBbls/d,
which is expected to be in service by the third quarter of 2004, will provide
producers with access to onshore delivery points in Texas and Louisiana. BP
p.l.c., BHP Billiton and Unocal have dedicated 86,400 acres of property to this
pipeline for the life of the reserves, including the acreage underlying their
Holstein, Mad Dog and Atlantis developments in the deeper water regions of the
Gulf of Mexico. In October 2002, we 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,
which we will operate. The formation of this 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.
We are contractually committed to the Cameron Highway Project whether or not we
obtain a partner. We expect that a majority of the costs of this project will be
funded through project financing. It is estimated that the majority of the
capital outlay for the project will occur in 2003 and 2004. As of September 30,
2002, we have spent approximately $3.1 million related to this pipeline, which
is in the development stage.

Falcon Nest

In April 2002, we entered into an agreement to construct and own the $53
million Falcon Nest fixed-leg platform, together with related pipelines, with
capacity to handle 300 MMcf/d of natural gas, which is expected to be in service
during the first quarter of 2003, designed and located to process natural gas
from Pioneer Natural Resources Company's and Mariner Energy, Inc.'s Falcon Field
discovery in the Gulf of Mexico. Pioneer and Mariner have dedicated 69,120 acres
of property, including acreage underlying their Falcon Field discovery, to this
platform for the life of the reserves. As of September 30, 2002, we have spent
approximately $18.2 million on this project, which is under construction.

Petal Expansion

In June 2002, we completed a $68 million, 8.9 Bcf (6.3 Bcf working
capacity) expansion of our Petal natural gas storage facility, including a
withdrawal facility and a 20,000 horsepower compression station, located near
Hattiesburg, Mississippi. This brings the total working gas capacity of the
Petal facility to 9.5 Bcf, of which 7 Bcf is dedicated to a subsidiary of The
Southern Company, one of the largest producers of electricity in the United
States, under a 20-year fixed-fee contract. In June 2002, we also completed a
$100 million, 60-mile pipeline addition with capacity of 1.25 Bcf/d (currently
FERC-certified to 700 MMcf/d) that interconnects with the storage facility and
offers direct interconnects with the Southern Natural Gas, Transco and Destin
pipeline systems. In June 2002, the interconnects with Southern Natural Gas and
Destin were placed into service. In September 2002, the Transco interconnect was
placed in service.

Red Hawk

In October 2002, we announced that we will build and operate a new $57
million, 16-inch pipeline to gather natural gas production from the Red Hawk
Field located in the Garden Banks area of the Gulf of Mexico. We have entered
into the related agreements with Kerr-McGee Oil and Gas Corporation, a wholly
owned subsidiary of Kerr-McGee Corporation and Ocean Energy, Inc., which each
hold a 50-percent working interest in the Red Hawk Field. The 86-mile pipeline,
capable of transporting up to approximately 330 MMcf/d of natural gas, will
originate in 5,300 feet of water at the Red Hawk Field and connect to the ANR
41

Pipeline system at Vermillion Block 397. We plan to place the new pipeline,
which is in the development stage, in service during the second quarter of 2004.

OTHER MATTERS

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

RELATED PARTY TRANSACTIONS

For a discussion of our related party transactions, see Part I, Financial
Information, Note 11. In our normal course of business we enter into
transactions with various entities controlled directly or indirectly by El Paso
Corporation, the parent of our general partner. In the third quarter of 2002,
$25 million of our related party revenue came from El Paso Merchant Energy North
America Company (Merchant Energy). Merchant Energy is a direct subsidiary of El
Paso Corporation. Approximately $15 million of this revenue represents the
proceeds received by us from selling to Merchant Energy hydrocarbons which we
gain title to month to month under certain gathering and processing agreements
with third party producers. These sales occur at market prices on an arms length
basis, and we believe these sales can be replaced by similar arrangements with
third parties at anytime should we so desire. The remaining $10 million of
revenue is primarily related to transportation services provided to Merchant
Energy by our pipelines, primarily the EPGT Texas intrastate pipeline system.
Merchant Energy has contracted with us on both a firm and interruptible basis
and currently utilizes its contracted capacity. In most cases these revenue
streams are originated by third parties.

Our largest related party revenue streams are generated by our three Texas
fractionation facilities and our Chaco plant. In the case of our fractionation
facilities, we are paid each month a fixed fee of $0.024 for each gallon of NGL
that we fractionate into its component parts. El Paso Field Services (Field
Services) an indirect subsidiary of El Paso Corporation, and a direct subsidiary
of El Paso Tennessee Pipeline Co., pays us this fee. Field Services receives the
NGL we fractionate at our facilities from producers in south Texas. The
fractionated NGL is re-delivered to Field Services at the tailgate of the plants
and then sold by Field Services to various petrochemical and refining customers
located along the Texas gulf coast. In addition, Field Services has gathering
and processing agreements with producers in the San Juan Basin. Field Services
pays us a fee of $0.1344 per dekatherm of natural gas that we process at the
Chaco plant. If we successfully close on our proposed acquisition of the San
Juan assets, we will be purchasing, among other assets, the contracts Field
Services has with the San Juan Basin producers and this related party revenue
stream will end.

SEGMENT RESULTS

In light of our expectation of acquiring additional natural gas pipeline
and processing assets, effective January 1, 2002, we revised and renamed our
business segments to reflect the change in composition of our operations. In
October 2001, we acquired the Chaco plant and reflected the operations of this
asset in our Oil and NGL logistics segment. With the change in our segments, we
moved the Chaco processing plant to our Natural gas pipelines and plants
segment. 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. Beginning in 2002, operations from our oil and natural gas production
activities are reflected in Other.

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.

42

The following table presents EBIT by segment and in total for each of the
quarter and nine months ended September 30:

EBIT variances are discussed in the segment results below.

NATURAL GAS PIPELINES AND PLANTS

In connection with our April 2002 EPN Holding asset acquisition, we added
assets to this segment with contracts whereby we may 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 prices. 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 for analyzing operating results for the Natural gas pipelines
and plants segment.

Third Quarter 2002 Compared to Third Quarter 2001

Natural gas pipelines and plants margin for the quarter ended September 30,
2002, was $60.2 million higher than in the same period in 2001. Approximately
$41.9 million of the increase was due to our April 2002 purchase of the EPN
Holding assets from subsidiaries of El Paso Corporation and $8.0 million to our
purchase of the Chaco plant in October 2001. Additionally, approximately $8.2
million of the increase was due to our consolidation of Deepwater Holdings in
October 2001. Further contributing to the increase was $1.2 million relating to
our purchase of the Big Thicket assets in August 2002 and $0.5 million relating
to the operations of the Pelican Stabilizer, which was placed in service in
March 2002. Excluding the contribution from these

43

newly acquired assets, margins increased by $1.4 million. Offsetting these
increases was a $1 million mark-to-market non-cash loss associated with a
derivative transaction we entered into during the quarter to economically hedge
a portion of the 2003 price risk exposure for gathering services associated with
our proposed San Juan acquisition. In addition, our third quarter 2002 margin
decreased by $0.6 million as a result of Hurricane Isidore in September 2002. We
expect our fourth quarter margins to be lower due to Hurricane Lili which
occurred in October 2002. Offsetting this fourth quarter impact, will be
additional volumes from the startup of production in the Camden Hills and
Aconcagua Fields which will be delivered to our Viosca Knoll system.

Operating expenses for the quarter ended September 30, 2002, were $33.9
million higher than the same period in 2001 primarily due to our April 2002
purchase of the EPN Holding assets, our purchase of the Chaco plant in October
2001, and our consolidation of Deepwater Holdings. Excluding the operating costs
of the newly acquired assets, operating expenses increased by $1.3 million due
to accelerated non-routine maintenance on our HIOS system, as well as a bad debt
write-off.

Other income (loss) for the quarter ended September 30, 2002, was $0.4
million lower than the same period in 2001 primarily due to purchase price
adjustments related to Deepwater's sale of Stingray, UTOS and the West Cameron
dehydration facility. After our acquisition of the remaining interest in
Deepwater Holdings in October 2001, Deepwater Holdings became a consolidated
subsidiary.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

Natural gas pipeline and plants margin for the nine months ended September
30, 2002, was $139.4 million higher than the same period in 2001. Approximately
$83.3 million of the increase was due to our April 2002 purchase of the EPN
Holding assets from subsidiaries of El Paso Corporation and $24.4 million to our
purchase of the Chaco plant in October 2001. Additionally, approximately $27.4
million of the increase was due to our consolidation of Deepwater Holdings in
October 2001. Further contributing to the increase was $1.2 million relating to
our purchase of the Big Thicket assets in August 2002 and $0.6 million relating
to the operations of the Pelican Stabilizer, which was placed in service in
March 2002. Excluding the contribution from these newly acquired assets, margins
increased by $3.5 million. Offsetting these increases was a $1 million
mark-to-market non-cash loss associated with a derivative transaction we entered
into during the third quarter to economically hedge a portion of the 2003 price
risk exposure for gathering services associated with our proposed San Juan
acquisition. In addition, our 2002 margin decreased by $0.6 million as a result
of Hurricane Isidore in September 2002. We expect our fourth quarter margins to
be lower due to Hurricane Lili which occurred in October 2002. Offsetting this
fourth quarter impact, will be additional volumes from the startup of production
in the Camden Hills and Aconcagua Fields which will be delivered to our Viosca
Knoll system.

Operating expenses for the nine months ended September 30, 2002 were $71.9
million higher than the same period in 2001 primarily due to our April 2002
purchase of the EPN Holding assets, our purchase of the Chaco plant in October
2001, and our consolidation of Deepwater Holdings. Excluding the operating costs
of the newly acquired assets, operating expenses increased by $3.7 million.

Other income for the nine months ended September 30, 2002, was $4.5 million
lower than the same period in 2001 primarily due to our recognition in 2001 of
$22.0 million in additional consideration from El Paso Corporation associated
with the sale of our Gulf of Mexico pipeline assets in 2001, partially offset by
net losses of $7.8 million due to the sale of our interests in the Tarpon and
Green Canyon pipeline assets in January 2001. Also contributing to this offset
were lower earnings from unconsolidated affiliates of $10.3 million, which
primarily relates to Deepwater Holdings' sale of Stingray, UTOS and the West
Cameron dehydration facility and the sale of our interest in Nautilus and Manta
Ray Offshore in 2001.

44

OIL AND NGL LOGISTICS

- ----------

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

Third Quarter 2002 Compared to Third Quarter 2001

For the quarter ended September 30, 2002, revenues were $0.7 million lower
than the same period in 2001 primarily due to lower volumes on EPN Texas.
Offsetting this decrease was our acquisitions of the Hattiesburg propane storage
facility in January 2002 and the Anse La Butte NGL storage facility in December
2001 and higher volumes on Allegheny.

Operating expenses for the quarter ended September 30, 2002, were $0.2
million higher than the same period in 2001 primarily due to our acquisition of
the Hattiesburg propane storage facility in January 2002 and the Anse La Butte
NGL storage facility in December 2001 offset by the modification of the
operating agreement in connection with the EPN Holding acquisition in April 2002
between EPN Texas and El Paso Field Services, which reduced the amount of
monthly operating charges to us.

Other income for the quarter ended September 30, 2002, was $0.3 million
lower than the same period in 2001 primarily due to a decrease in earnings from
unconsolidated affiliates due to lower volumes on Poseidon Oil Pipeline
partially attributable to Hurricane Isidore in September 2002. We expect our
fourth quarter earnings from unconsolidated affiliates to be lower due to
Hurricane Lili which occurred in October 2002. Offsetting this fourth quarter
impact, will be additional volumes related to new contracts that Poseidon Oil
Pipeline has entered into. These contracts start in November 2002 and December
2002 and have a six month duration. We will realize our 36 percent share of the
volume increase through earnings from unconsolidated affiliates over the next
seven months.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

For the nine months ended September 30, 2002, revenues were $5.2 million
higher than the same period in 2001 primarily due to our acquisitions of the EPN
Texas transportation and fractionation assets in February 2001, the Hattiesburg
propane storage facility in January 2002, and the Anse La Butte NGL storage
facility in December 2001. Additionally, higher volumes on Allegheny also
contributed to the increase in revenues.

Operating expenses for the nine months ended September 30, 2002, were $3.2
million higher than the same period in 2001 primarily due to our acquisitions of
the EPN Texas transportation and fractionation assets in February 2001, the
Hattiesburg propane storage facility in January 2002, and the Anse La Butte NGL
storage facility in December 2001.

Other income for the nine months ended September 30, 2002, was $2.4 million
lower than the same period in 2001 primarily due to a decrease in earnings from
unconsolidated affiliates due to lower volumes on Poseidon Oil Pipeline
partially attributable to Hurricane Isidore in September 2002. We expect our
fourth
45

quarter earnings from unconsolidated affiliates to be lower due to Hurricane
Lili which occurred in October 2002. Offsetting this fourth quarter impact, will
be additional volumes related to new contracts that Poseidon Oil Pipeline has
entered into. These contracts start in November 2002 and December 2002 and have
a six month duration. We will realize our 36 percent share of the volume
increase through earnings from unconsolidated affiliates over the next seven
months.

NATURAL GAS STORAGE

Third Quarter 2002 Compared to Third Quarter 2001

For the quarter ended September 30, 2002, revenues were $4.0 million higher
than the same period in 2001 primarily due to the expansion of the Petal storage
facility and our acquisition of the Wilson storage facility lease in April 2002.
Storage capacity for the Petal facility has been subscribed to a subsidiary of
the Southern Company for 7.0 Bcf and to BP for 1.65 Bcf.

Expansion of the Petal storage facility was completed during the second
quarter, and we commenced services to a subsidiary of the Southern Company in
the third quarter of 2002. Petal's services under this contract will add $4.0
million of revenues during the fourth quarter of 2002.

Operating expenses for the quarter were $3.0 million higher than the same
period in 2001 primarily due to the expansion of our Petal storage facility in
the second quarter of 2002 and the acquisition of the Wilson storage facility
lease in April 2002.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

For the nine months ended September 30, 2002, revenues were $3.4 million
higher than the same period in 2001 primarily due to the expansion of the Petal
storage facility and our acquisition of the Wilson storage facility lease in
April 2002. This increase was partially offset by a decrease in revenues
attributable to lower commodity revenues and interruptible storage services at
our Hattiesburg facility during 2002.

Operating expenses for the nine months ended September 30, 2002, were $5.3
million higher than the same period in 2001 primarily due to the expansion of
our Petal storage facility in the second quarter of 2002, the acquisition of the
Wilson storage facility lease in April 2002 and a favorable resolution of an
imbalance settlement in 2001.

46

PLATFORM SERVICES

Third Quarter 2002 Compared to Third Quarter 2001

For the quarter ended September 30, 2002, revenues were $1.8 million lower
than in the same period in 2001 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 Flextrend Development
Company, our wholly owned subsidiary. Operating expenses for the same periods
were $0.2 million higher due to higher direct costs.

Other income for the quarter ended September 30, 2002 reflects income from
an intersegment investment that is eliminated in our Other segment in
consolidation.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

For the nine months ended September 30, 2002, revenues were $0.2 million
lower than the same period in 2001 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 Flextrend Development
Company, our wholly owned subsidiary, partially offset by retroactive billings
for fixed monthly platform access fees and a retroactive gas dehydration fee on
the East Cameron 373 platform. Operating expenses for the same periods were $0.9
million lower due to lower direct costs.

Other income for the nine months ended September 30, 2002 reflects income
from an intersegment investment that is eliminated in our Other segment in
consolidation. Other loss for the nine months ended September 30, 2001 reflects
approximately $3.0 million of losses recognized on the sales of our Gulf of
Mexico platform assets in January 2001, offset by the additional consideration
from El Paso Corporation related to the sale of these assets.

OTHER, NET

Third Quarter 2002 Compared to Third Quarter 2001

Earnings before interest expense and taxes related to non-segment activity
for the quarter ended September 30, 2002, were $0.2 million higher than the same
period in 2001. The increase was primarily due to higher natural gas and oil
prices offset by lower volumes attributable to a decrease in natural gas
production as a result of normal decline of existing reserves. Third quarter
2002 EBIT also decreased by $0.2 million as a

47

result of Hurricane Isidore in September 2002. We expect our fourth quarter 2002
EBIT to be lower due to Hurricane Lili which occurred in October 2002.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

Earnings before interest expense and taxes related to non-segment activity
for the nine months ended September 30, 2002, were $6.0 million lower than the
same period in 2001. The decrease was primarily due to lower natural gas and oil
prices, as well as lower volumes attributable to a decrease in natural gas
production as a result of normal decline of existing reserves, partially offset
by lower operating expenses and depletion. Additionally, EBIT decreased by $0.2
million as a result of Hurricane Isidore in September 2002. We expect our fourth
quarter 2002 EBIT to be lower due to Hurricane Lili which occurred in October
2002.

INTEREST AND DEBT EXPENSE

Interest and debt expense, net of capitalized interest, for the quarter and
nine month periods ended September 30, 2002, was approximately $12.2 million and
$25.9 million higher than the same periods in 2001. This increase is primarily
due to an increase in the average outstanding balance of our revolving credit
facility, the amounts outstanding under the EPN Holding acquisition facility
which we entered to purchase the EPN Holding assets in April 2002, and the $230
million of 8.5% senior subordinated notes issued in May 2002. Capitalized
interest for the quarter and nine months ended September 30, 2002 was $0.7
million and $4.3 million compared to $3.4 million and $9.7 million for the same
periods in 2001.

COMMITMENTS AND CONTINGENCIES

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

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

48

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

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

- earnings per unit;

- capital and other expenditures;

- cash distributions;

- financing plans;

- capital structure;

- liquidity and cash flow;

- pending legal proceedings and claims, including environmental matters;

- future economic performance;

- operating income;

- cost savings;

- management's plans; and

- goals and objectives for future operations.

Important factors that could cause actual results to differ materially from
estimates or projections contained in forward-looking statements are described
in our Annual Report on Form 10-K for the year ended December 31, 2001, 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,

49

2001, 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 and 8-K/A.

In August 2002, we entered into a derivative financial instrument to hedge
our exposure during 2003 relating to gathering activities for changes in natural
gas prices in the San Juan Basin in anticipation of our proposed 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 upon the San Juan index. We are accounting for this derivative under
mark-to-market accounting since it does not qualify for hedge accounting under
SFAS 133. As of September 30, 2002, the fair value of this derivative was a $1.0
million liability and we recognized this $1.0 million loss in the margin of our
Natural gas pipelines and plants segment. Once the proposed acquisition of the
San Juan assets is completed, we expect to designate this derivative as a cash
flow hedge under SFAS 133.

During 2001 and 2002, we entered into cash flow hedges in connection with
our EPIA operations. As of September 30, 2002, the fair value of these cash flow
hedges was an asset of approximately $49 thousand. During the nine months ended
September 30, 2002, the majority of our cash flow hedges expired and we
reclassified $1.4 million from accumulated other comprehensive income to
earnings.

Starting in April 2002, in connection with our EPN Holdings acquisition, we
have swaps in place for our interest in the Indian Basin processing plant. As of
September 30, 2002, the fair value of these cash flow hedges was a $126 thousand
liability resulting in an unrealized loss of $126 thousand.

During 2002, Poseidon entered into a two-year interest rate swap agreement.
As of September 30, 2002, the fair value of its interest rate swap was a
liability of $1.6 million resulting in an unrealized loss of $1.6 million. We
include our 36 percent share of this liability of $0.6 million as a reduction of
our investment in Poseidon and as an unrealized loss in other comprehensive
income. Additionally, we have recognized in income our 36 percent share of
Poseidon's realized loss of $0.9 million for the nine months ended September 30,
2002, or $0.3 million, through our earnings from unconsolidated affiliates.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our 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 within 90 days of the filing date of this quarterly
report pursuant to Rules 13a-15 and 15d-15 under the Securities Exchange Act of
1934 (the "Exchange Act"). Based on that evaluation, our principal executive
officer and principal financial officer have concluded that these controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.

Disclosure controls and procedures 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 and procedures 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.

The principal executive officer and principal financial officer
certifications required under Sections 302 and 906 of the Sarbanes-Oxley Act of
2002 have been included herein, or as Exhibits to this Quarterly Report on Form
10-Q, as appropriate.

50

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

In October 2002, we announced changes in our Board of Directors, designed
to align us with certain corporate governance recommendations recently announced
by the New York Stock Exchange. Robert G. Phillips has been elected Chairman of
the Board of Directors of El Paso Energy Partners Company, our general partner.
The Board also accepted the resignations of William A. Wise, H. Brent Austin,
and Malcom Wallop.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

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

UNDERTAKING

We hereby undertake, pursuant to Regulation S-K Items 601(b), paragraph
(4)(iii), to furnish to the U.S. Securities and Exchange Commission, upon
request, all constituent instruments defining the rights of holders of our
long-term debt not filed herewith for the reason that the total amount of
securities authorized under any such instruments does not exceed 10 percent of
our total consolidated assets.

(b) Reports on Form 8-K

We filed a current report on Form 8-K dated July 15, 2002, to conform our
historical financial information as of December 31, 2001 and 2000, and for the
years ended December 31, 2001, 2000 and 1999 to the presentation in our Form
10-Q for the quarterly period ended March 31, 2002, which reflected new names
for our segments, movement of the Chaco processing plant from Oil and NGL
logistics to Natural gas pipelines and plants segment, and discontinued
operations treatment for assets held for sale.

We filed a current report on Form 8-K/A dated July 19, 2002, to include the
signature page inadvertently omitted from our Form 8-K dated July 15, 2002.

We filed a current report on Form 8-K dated July 31, 2002, providing
unaudited financial statements of the Texas and New Mexico midstream assets
acquired from El Paso Corporation at March 31, 2002 and for the three month
periods ended March 31, 2002 and 2001.

We filed a current report on Form 8-K dated August 12, 2002, discussing the
proposed acquisition of the San Juan assets; providing audited combined
financial statements of El Paso Field Services San Juan Gathering and Processing
Businesses, Typhoon Gas Pipeline, Typhoon Oil Pipeline, and Coastal Liquids
Partners NGL Business as of December 31, 2001 and 2000, and for the years ended
December 31, 2001, 2000 and 1999; providing unaudited combined financial
statements for these businesses as of March 31, 2002, and for the three months
ended March 31, 2002 and 2001; providing unaudited proforma condensed
consolidated and combined financial statements to (i) reflect the expected
issuance of long-term debt and equity to generate cash proceeds and (ii) reflect
the use of such proceeds for the acquisition of the San Juan assets from El Paso
Corporation; and providing certifications with respect to such current report on
Form 8-K.

52

We filed a current report on Form 8-K dated October 8, 2002 announcing
Valero Energy Corporation as a 50 percent partner in the Cameron Highway Oil
pipeline project.

We filed a current report on Form 8-K dated October 10, 2002 updating the
current risk factors discussion, discussing the use of various performance
measures, updating the financial statements and pro forma financial information
previously filed in connection with the proposed acquisition of the San Juan
assets and updating the balance sheet of our general partner, El Paso Energy
Partners Company.

We filed a current report on Form 8-K dated October 10, 2002 announcing
plans to build and operate a new 85-mile, 16 inch pipeline to gather natural gas
production from the Red Hawk field.

We filed a current report on Form 8-K dated October 18, 2002 to announce
changes in our Board of Directors.

53

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.

EL PASO ENERGY PARTNERS, L.P.

By: EL PASO ENERGY PARTNERS COMPANY,
its General Partner

Date: November 12, 2002 By: /s/ KEITH B. FORMAN
------------------------------------
Keith B. Forman
Vice President and Chief Financial
Officer

Date: November 12, 2002 By: /s/ D. MARK LELAND
------------------------------------
D. Mark Leland
Senior Vice President and Controller
(Principal Accounting Officer)

54

CERTIFICATION

I, Robert G. Phillips, certify that:

1. I have reviewed this quarterly report on Form 10-Q of El Paso 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: November 12, 2002

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

55

CERTIFICATION

I, Keith B. Forman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of El Paso 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: November 12, 2002

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

56

INDEX TO EXHIBITS