DUKE ENERGY FIELD SERVICES LLC, 424B5, 2000-08-07

DUKE ENERGY FIELD SERVICES LLC
424B5, 2000-08-07
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

THE INFORMATION IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING
PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. THIS PROSPECTUS SUPPLEMENT
AND THE ACCOMPANYING PROSPECTUS ARE NOT AN OFFER TO SELL THESE SECURITIES
AND WE ARE NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE
WHERE THE OFFER OR SALE IS NOT PERMITTED.

Filed pursuant to Rule 424(b)(5)
Registration No. 333-41854
SUBJECT TO COMPLETION

PRELIMINARY PROSPECTUS SUPPLEMENT DATED AUGUST 3, 2000

PROSPECTUS SUPPLEMENT
----------------------------------
(TO PROSPECTUS DATED AUGUST 2, 2000)

[DUKE ENERGY FIELD SERVICES LOGO]

DUKE ENERGY FIELD SERVICES, LLC
$ % NOTES DUE
$ % NOTES DUE
----------------------
We are offering and selling an aggregate of $ of our % notes due
and an aggregate of $ of our % notes due .

Interest on the notes of each series is payable on February and August
of each year, beginning on February , 2001. The % notes will mature
on August , and the % notes will mature on August , . We
may redeem some or all of our notes at any time. We describe the redemption
price under the heading "Description of the Notes -- Optional Redemption" on
page S-47 of this prospectus supplement. We will also pay accrued interest to
the date of any redemption.

The notes of each series are unsecured and rank equally with all of our
other unsecured and senior indebtedness. The notes will not be entitled to the
benefit of any sinking fund.
----------------------

<TABLE>
<CAPTION>
PUBLIC OFFERING UNDERWRITING PROCEEDS, BEFORE
PRICE(1) DISCOUNT EXPENSES TO US
--------------- ------------ ----------------
<S> <C> <C> <C>
Per Note due............................................... % % %
Total...................................................... $ $ $
Per Note due............................................... % % %
Total...................................................... $ $ $
</TABLE>

(1) Plus accrued interest from , 2000, if settlement occurs after
that date

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus supplement or the attached prospectus is truthful or complete. Any
representation to the contrary is a criminal offense.

The notes of each series will be ready for delivery on or about August
, 2000.

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

JOINT BOOK-RUNNING MANAGERS

MERRILL LYNCH & CO. J.P. MORGAN & CO.
----------------------

BANC OF AMERICA SECURITIES LLC
CHASE SECURITIES INC.
LEHMAN BROTHERS
MORGAN STANLEY DEAN WITTER
----------------------
The date of this prospectus supplement is August , 2000.
<PAGE> 2

OWNERSHIP OF OUR COMPANY

We are Duke Energy Field Services, LLC, the issuer of the notes offered by
this prospectus supplement. On March 31, 2000, the North American midstream
natural gas gathering, processing, marketing and natural gas liquids businesses
of Duke Energy Corporation ("Duke Energy") and Phillips Petroleum Company
("Phillips") were combined into our company.

The following diagram is a summary of the ownership structure of our
company. Each of Duke Energy and Phillips own both common and preferred
membership interests in our company.

Graph
<PAGE> 3

TABLE OF CONTENTS

PROSPECTUS SUPPLEMENT

<TABLE>
<CAPTION>
PAGE
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<S> <C>
Prospectus Supplement Summary............................... S-4
Use of Proceeds............................................. S-13
Capitalization.............................................. S-13
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-14
Business.................................................... S-28
Description of the Notes.................................... S-47
Underwriting................................................ S-50
Validity of the Notes....................................... S-51
Index to Financial Statements............................... F-1

PROSPECTUS
</TABLE>

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
About this Prospectus....................................... 2
Where You Can Find More Information......................... 2
Cautionary Statement about Forward-Looking Statements....... 3
Our Company................................................. 4
Ratio of Earnings to Fixed Charges.......................... 6
Use of Proceeds............................................. 6
Description of Debt Securities.............................. 7
Plan of Distribution........................................ 16
Experts..................................................... 18
Validity of the Securities.................................. 18
</TABLE>

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

You should rely only on the information contained or incorporated by
reference in this prospectus supplement and the accompanying prospectus. We have
not, and the underwriters have not, authorized any other person to provide you
with different information. If anyone provides you with different or
inconsistent information, you should not rely on it. If this prospectus
supplement is inconsistent with the accompanying prospectus, you should rely on
this prospectus supplement. We are not, and the underwriters are not, making an
offer to sell these securities in any jurisdiction where the offer or sale is
not permitted. You should assume that the information in this prospectus
supplement and the accompanying prospectus is accurate only as of the respective
dates on the front of those documents or earlier dates specified therein. Our
business, financial condition, results of operations and prospects may have
changed since those dates.

S-3
<PAGE> 4

PROSPECTUS SUPPLEMENT SUMMARY

This summary highlights information contained elsewhere in this prospectus
supplement and the accompanying prospectus. This summary does not contain all of
the information that you should consider before investing in our notes. You
should read this entire prospectus supplement and the accompanying prospectus
carefully, including the historical and pro forma financial statements and
related notes, before making an investment decision.

Duke Energy Field Services, LLC was recently formed to hold the combined
North American midstream natural gas gathering, processing, marketing and
natural gas liquids businesses of Duke Energy Corporation and Phillips Petroleum
Company. The transaction in which those businesses were combined is referred to
in this prospectus supplement as the "Combination." Our limited liability
company agreement limits the scope of our business to the midstream natural gas
industry in the United States and Canada, the marketing of natural gas liquids
in Mexico and the transportation, marketing and storage of other petroleum
products, unless otherwise approved by our Board of Directors.

Unless the context otherwise requires, descriptions of assets, operations
and results in this prospectus supplement give effect to the Combination and
related transactions, the transfer to us of additional midstream natural gas
assets acquired by Duke Energy or Phillips prior to the Combination and the
transfer to us of the general partner of TEPPCO Partners, L.P., all of which are
described in more detail under "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- The Combination." In this
prospectus supplement, the terms "we," "us" and "our" refer to Duke Energy Field
Services, LLC and our subsidiaries, giving effect to the Combination and related
transactions.

OUR BUSINESS

The midstream natural gas industry is the link between exploration and
production of raw natural gas and the delivery of its components to end-use
markets. We operate in the two principal segments of the midstream natural gas
industry:

- natural gas gathering, processing, transportation, marketing and storage;
and

- natural gas liquids ("NGLs") fractionation, transportation, marketing and
trading.

- we gathered and/or transported an average of approximately 7.3 billion
cubic feet per day of raw natural gas;

- we produced an average of approximately 400,000 barrels per day of NGLs;
and

- we marketed and traded an average of approximately 486,000 barrels per
day of NGLs.

During 1999, our natural gas gathering, processing, transportation,
marketing and storage segment produced $981.5 million of gross margin and $592.4
million of EBITDA, excluding general and administrative expenses, and our NGL
fractionation, transportation, marketing and trading segment produced $38.3
million of gross margin and $38.1 million of EBITDA, excluding general and
administrative expenses. During the six months ended June 30, 2000, our natural
gas gathering, processing, transportation, marketing and storage segment
produced $657.1 million of gross margin and $484.4 million of EBITDA, excluding
general and administrative expenses, and our NGL fractionation, transportation,
marketing and trading segment produced $26.5 million of gross margin and $26.1
million of EBITDA, excluding general and administrative expenses.

We gather raw natural gas through gathering systems located in seven major
natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin
Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of
Mexico and Western Canada. Our gathering systems consist
S-4
<PAGE> 5

of approximately 57,000 miles of gathering pipe, with approximately 38,000
active connections to producing wells.

Our natural gas processing operations involve the separation of raw natural
gas gathered both by our gathering systems and by third-party systems into NGLs
and residue gas. We process the raw natural gas at our 70 owned and operated
plants and at 13 third-party operated facilities in which we hold an equity
interest.

The NGLs separated from the raw natural gas by our processing operations
are either sold and transported as NGL raw mix or further separated through a
process known as fractionation into their individual components (ethane,
propane, butanes and natural gasoline) and then sold as components. We
fractionate NGL raw mix at our 12 owned and operated processing facilities and
at two third-party operated fractionators located on the Gulf Coast in which we
hold an equity interest.

We sell NGLs to a variety of customers ranging from large, multi-national
petrochemical and refining companies to small regional retail propane
distributors. Substantially all of our NGL sales are made at market-based
prices, including approximately 40% of our NGL production that is committed to
Phillips under a 15-year contract. We market approximately 370,000 barrels per
day of NGLs processed at our owned and operated plants and 40,000 barrels per
day of NGLs processed at third-party operated facilities and trade approximately
75,000 barrels per day of NGLs at market centers.

The residue gas that results from our processing is sold at market-based
prices to marketers or end-users, including large industrial customers and
natural gas and electric utilities serving individual consumers. We market
residue gas through our wholly owned gas marketing company. We also store
residue gas at our 8.5 billion cubic foot natural gas storage facility.

On March 31, 2000, we obtained by transfer from Duke Energy the general
partner of TEPPCO Partners, L.P. ("TEPPCO"), a publicly traded limited
partnership which owns and operates a network of pipelines for refined products
and crude oil. The general partner is responsible for the management and
operations of TEPPCO. We believe that our ownership of the general partner of
TEPPCO improves our business position in the transportation sector of the
midstream natural gas industry and provides additional flexibility in pursuing
our disciplined acquisition strategy by providing an alternative acquisition
vehicle. It also provides us with an opportunity to sell appropriate assets
currently held by our company to TEPPCO. Through our ownership of the general
partner of TEPPCO we have the right to receive from TEPPCO incentive cash
distributions in addition to a 2% share of distributions based on our general
partner interest. At TEPPCO's 1999 per unit distribution level, the general
partner:

- receives approximately 14% of the cash distributed by TEPPCO to its
partners, which consists of 12% from the incentive cash distribution
and 2% from the general partner interest; and

- under the incentive cash distribution provisions, receives 50% of
any increase in TEPPCO's per unit cash distributions.

On July 21, 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield
Company's ownership interests in a 500-mile crude oil pipeline that extends from
a marine terminal at Freeport, Texas to Cushing, Oklahoma, a 416-mile crude oil
pipeline that extends from Jal, New Mexico to Cushing, a 400-mile crude oil
pipeline that extends from West Texas to Houston, crude oil terminal facilities
in Midland, Texas, Cushing and the Houston area and receipt and delivery
pipelines centered around Midland.

OUR BUSINESS STRATEGY

We believe that we are one of the largest gatherers of raw natural gas,
based on wellhead volume, in North America. We are the largest producer, and we
believe that we are one of the largest marketers, of NGLs in North America. Our
limited liability company agreement limits the scope of our business to the
midstream natural gas industry in the United States and Canada, the marketing of
NGLs in Mexico, and the transportation, marketing and storage of other petroleum
products, unless otherwise approved by our board of directors. We have
significant midstream natural gas operations in five of the largest natural gas
S-5
<PAGE> 6

producing regions in North America. To take advantage of anticipated growth in
natural gas demand in North America, we are pursuing the following strategies:

- Capitalize on the size and focus of our existing operations. We intend to
use the size, scope and concentration of our assets in our regions of
operation to take advantage of growth opportunities and to acquire
additional supplies of raw natural gas. Our significant market presence
and asset base generally provide us with a competitive advantage in
capturing new supplies of raw natural gas because of our resulting lower
costs of connection to new wells and of processing additional raw natural
gas. In addition, we believe our size and geographic diversity allow us
to benefit from the growth of natural gas production in multiple regions
while mitigating the adverse effects from a downturn in any one region.

- Increase our presence in each aspect of the midstream business. We are
active in each significant aspect of the midstream natural gas value
chain, including raw natural gas gathering, processing, and
transportation, NGL fractionation and NGL and residue gas transportation
and marketing. Each link in the value chain provides us with an
opportunity to earn incremental income from the raw natural gas that we
gather and from the NGLs and residue gas that we produce. We intend to
grow our significant NGL market presence by investing in additional NGL
infrastructure, including pipelines, fractionators and terminals.

- Increase our presence in high growth production areas. According to the
Energy Information Administration's report "Annual Energy Outlook 2000"
(the "EIA Report"), production from areas such as Western Canada, Onshore
Gulf of Mexico, Rocky Mountains and Offshore Gulf of Mexico is expected
to increase significantly to meet anticipated increases in demand for
natural gas in North America. We intend to use our strategic asset base
in these growth areas and our leading position in the midstream natural
gas industry as a platform for future growth in these areas. We plan to
increase our operations in these areas by following a disciplined
acquisition strategy, and by expanding existing infrastructure and
constructing new gathering lines and processing facilities.

- Capitalize on proven acquisition skills in a consolidating industry. In
addition to pursuing internal growth by attracting new raw natural gas
supplies, we intend to use our substantial acquisition and integration
skills to continue to participate selectively in the consolidation of the
midstream natural gas industry. We have pursued a disciplined acquisition
strategy focused on acquiring complementary assets during periods of
relatively low commodity prices and integrating the acquired assets into
our operations. Since 1996, we have completed over 20 acquisitions,
increasing our raw natural gas processing capacity by over 275%. These
acquisitions demonstrate our ability to successfully identify, acquire
and integrate attractive midstream natural gas operations.

- Further streamline our low-cost structure. Our economies of scale,
operating efficiency and resulting low cost structure enhance our ability
to attract new raw natural gas supplies and generate current income. The
low-cost provider in any region can more readily attract new raw natural
gas volumes by offering more competitive terms to producers. We believe
the Combination provides us with a complementary base of assets from
which to further extract operating efficiencies and cost reductions,
while continuing to provide superior customer service.

We are a Delaware limited liability company, and we were formed on December
15, 1999. Our principal executive offices are located at 370 17th Street, Suite
900, Denver, Colorado 80202, and our telephone number is (303) 595-3331.

S-6
<PAGE> 7

THE OFFERING

Offered Securities......... $ principal amount of % notes due
$ principal amount of % notes due

Maturity Dates............. % notes -- August ,
% notes -- August ,

Interest Payment Dates..... February and August of each year,
commencing February , 2001.

Optional Redemption........ Each series of notes will be redeemable in whole or
in part, at our option at any time, at redemption
prices as set forth herein under "Description of
the Notes -- Optional Redemption."

Ranking.................... Each series of notes will be our direct, unsecured
and senior obligations and will rank equal in
priority with any other series of notes and with
our other unsecured and senior indebtedness.

Ratings.................... The notes of each series have been assigned ratings
of BBB by Standard & Poor's Ratings Services, Baa2
by Moody's Investors Service, Inc. and BBB by Fitch
IBCA, Inc. These ratings services will continue to
monitor our debt ratings and will make future
adjustments to the extent warranted. Each rating
reflects only the views of Standard & Poor's
Ratings Services, Moody's Investors Service, Inc.
or Fitch IBCA, Inc., as the case may be, and is not
a recommendation to buy, sell or hold the notes.
There is no assurance that any such rating will be
retained for any given period of time or that it
will not be revised downward or withdrawn entirely
by Standard & Poor's Ratings Services, Moody's
Investors Service, Inc. or Fitch IBCA, Inc., as the
case may be, if, in their respective judgments,
circumstances warrant. Any such downward revision
or withdrawal of any rating may have an adverse
effect on the market price or marketability of the
notes.

Interest Rates............. Each series of notes will bear interest at the
annual rate contained in its title.

Certain Covenants.......... The Indenture governing the notes contains certain
covenants that, among other things:

- limit our ability and the ability of our
subsidiaries to create liens and enter into sale
and leaseback transactions; and

- limit our ability to engage in mergers and
consolidations or transfer substantially all of
our assets.

See "Description of Debt Securities" in the
accompanying prospectus.

Use of Proceeds............ The net proceeds from the offering of the notes
will be used to repay outstanding commercial paper.
See "Use of Proceeds."

S-7
<PAGE> 8

PRESENTATION OF FINANCIAL INFORMATION AND OTHER DATA

Duke Energy Field Services, LLC is a new company that holds the combined
North American midstream natural gas businesses of Duke Energy and Phillips.

Because our operations have only recently been combined and these
operations have grown significantly through acquisitions, our historical and pro
forma financial information and operating data may not provide an accurate
indication of:

- what our actual results would have been if the transactions presented on
a pro forma basis had actually been completed as of the dates presented;
or

- what our future results of operations are likely to be.

HISTORICAL FINANCIAL AND OTHER DATA

From a financial reporting perspective, we are the successor to Duke
Energy's North American midstream natural gas business. The subsidiaries of Duke
Energy that conducted this business were contributed to Duke Energy Field
Services, LLC immediately prior to the Combination on March 31, 2000. For
periods prior to the Combination, Duke Energy Field Services, LLC and these
former subsidiaries of Duke Energy are collectively referred to in this
prospectus supplement as the "Predecessor Company." The historical financial
statements and related financial and other data for periods prior to March 31,
2000 included in this prospectus supplement reflect the business of the
Predecessor Company. The historical financial information and other data
included in this prospectus supplement should be viewed in light of the
following:

- the Combination is reflected as a March 31, 2000 acquisition of the
midstream natural gas business contributed to our company by Phillips in
the Combination;

- the Predecessor Company's acquisition of Union Pacific Fuels is reflected
as a March 31, 1999 acquisition by the Predecessor Company; and

- the historical financial statements for periods prior to March 31, 2000
included in this prospectus supplement do not include the results of the
general partner of TEPPCO.

For your additional information, we have also included the audited
financial statements of:

- the midstream natural gas business of Phillips that was transferred to us
in the Combination; and

- Union Pacific Fuels.

PRO FORMA FINANCIAL AND OTHER INFORMATION

In addition to the historical financial information and other data, this
prospectus supplement includes:

- unaudited pro forma income statements of our company for 1999 and the six
months ended June 30, 2000, each reflecting:

- the Combination;

- the Predecessor Company's acquisition of Union Pacific Fuels;

- the transfer to us of additional midstream natural gas assets
acquired by Duke Energy or Phillips prior to consummation of the
Combination;

- the transfer to us of the general partner of TEPPCO;

- the issuance of an aggregate of $300 million of preferred membership
interests in our company to affiliates of Duke Energy and Phillips
and the application of the proceeds therefrom; and

- the issuance of the notes offered hereby and the application of the
net proceeds therefrom;

in each case as if the transactions had occurred on January 1, 1999;

- an unaudited pro forma balance sheet of our company as of June 30, 2000
reflecting:

- the issuance of our preferred membership interests to affiliates of Duke
Energy and Phillips and the application of the proceeds therefrom; and

- the issuance of the notes offered hereby and the application of the net
proceeds therefrom;

in each case as if the transactions had occurred on June 30, 2000; and

- additional financial and other data giving effect to the Union Pacific
Fuels acquisition and the Combination, as if each had occurred on January
1, 1995.
S-8
<PAGE> 9

SELECTED HISTORICAL AND PRO FORMA
FINANCIAL AND OTHER DATA

The following tables set forth selected historical financial and other
data. The historical income statement data and cash flow data for each of the
three years ended December 31, 1999 and the historical balance sheet data as of
December 31 in each of those three years have been derived from the Predecessor
Company's audited historical financial statements. The historical financial
information for 1995 and 1996 and the six months ended June 30, 1999 and 2000 is
derived from unaudited financial statements. The historical data set forth below
for periods ending on or prior to March 31, 2000 relates only to the Predecessor
Company and does not reflect the results of operations or financial condition of
the Phillips businesses transferred to us in the Combination. In addition, the
following tables set forth selected pro forma financial and other data, which
reflect the historical data, adjusted for:

- the acquisition of the midstream natural gas business of Phillips in the
Combination;

- the acquisition of Union Pacific Fuels;

- incurrence of indebtedness to fund the cash distributions to Duke Energy
and Phillips in connection with the Combination as described in
"Management's Discussion and Analysis of Financial Condition and Results
of Operations;"

- the transfer to our company of additional midstream natural gas assets
acquired by Duke Energy prior to consummation of the Combination;

- the transfer to our company of the general partner of TEPPCO;

- the issuance of an aggregate of $300 million of preferred membership
interests in our company to affiliates of Duke Energy and Phillips and
the application of the proceeds therefrom; and

- the issuance of the notes offered hereby and the application of the net
proceeds therefrom;

as if all had occurred as of January 1, 1999 for income statement purposes and
June 30, 2000 for balance sheet purposes. The data should be read in conjunction
with the financial statements and related notes and other financial information
appearing elsewhere in this prospectus supplement. We are a recently combined
company, and the pro forma data set forth below are not necessarily indicative
of the results that we would have achieved if we had been a combined entity for
all periods presented or the results that may occur in the future.

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
------------------------------------------------------------- ----------
1995 1996 1997 1998 1999(1)(2) 1999(1)
-------- ---------- ---------- ---------- ----------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues:
Sales of natural gas and petroleum
products........................ $752,880 $1,321,111 $1,700,029 $1,469,133 $ 3,310,260 $5,268,927
Transportation, storage and
processing...................... 52,308 70,577 101,803 115,187 148,050 305,653
-------- ---------- ---------- ---------- ----------- ----------
Total operating revenues... 805,188 1,391,688 1,801,832 1,584,320 3,458,310 5,574,580
Costs and expenses:
Natural gas and petroleum
products........................ 601,533 1,070,805 1,468,089 1,338,129 2,965,297 4,554,776
Operating and maintenance......... 65,458 93,838 104,308 113,556 181,392 393,134
Depreciation and amortization..... 37,281 55,500 67,701 75,573 130,788 243,869
General and administrative........ 20,576 43,871 36,023 44,946 73,685 96,210
Net (gain) loss on sale of
assets.......................... (9,029) (2,350) (236) (33,759) 2,377 1,470
-------- ---------- ---------- ---------- ----------- ----------
Total costs and expenses... 715,819 1,261,664 1,675,885 1,538,445 3,353,539 5,289,459
Operating income.................... 89,369 130,024 125,947 45,875 104,771 285,121
Equity in earnings of unconsolidated
affiliates........................ 1,660 2,997 9,784 11,845 22,502 27,338
-------- ---------- ---------- ---------- ----------- ----------
Earnings before interest and tax.... 91,029 133,021 135,731 57,720 127,273 312,459
Interest expense.................... 20,115 12,747 51,113 52,403 52,915 183,840
-------- ---------- ---------- ---------- ----------- ----------
Earnings before income tax.......... 70,914 120,274 84,618 5,317 74,358 128,619
Income tax expense.................. 37,299 35,665 33,380 3,289 31,029 2,600
-------- ---------- ---------- ---------- ----------- ----------
Net income.......................... $ 33,615 $ 84,609 $ 51,238 $ 2,028 $ 43,329 $ 126,019
======== ========== ========== ========== =========== ==========
</TABLE>

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<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
--------------------------------------------------
HISTORICAL PRO FORMA
------------------------------ ----------
1999(8) 2000(8) 2000(8)
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues:
Sales of natural gas and petroleum products........ $1,032,880 $3,542,823 $4,132,807
Transportation, storage and processing............. 75,964 80,748 90,351
---------- ---------- ----------
Total operating revenues.................... 1,108,844 3,623,571 4,223,158
Costs and expenses:
Natural gas and petroleum products................. 916,310 3,115,037 3,539,618
Operating and maintenance.......................... 78,745 140,354 190,739
Depreciation and amortization...................... 56,006 105,359 129,848
General and administrative......................... 30,759 69,976 74,227
Net (gain) loss on sale of assets.................. (9) 337 249
---------- ---------- ----------
Total costs and expenses.................... 1,081,811 3,431,063 3,934,681
Operating income..................................... 27,033 192,508 288,477
Equity in earnings of unconsolidated affiliates...... 10,275 14,707 17,916
---------- ---------- ----------
Earnings before interest and tax..................... 37,308 207,215 306,393
Interest expense..................................... 25,535 59,851 91,470
---------- ---------- ----------
Earnings before income tax........................... 11,773 147,364 214,923
Income tax expense (benefit)......................... 5,618 (306,765) 4,300
---------- ---------- ----------
Net income........................................... $ 6,155 $ 454,129 $ 210,623
========== ========== ==========
OTHER DATA:
EBITDA(3)............................................ $ 93,314 $ 312,574 $ 436,241
Ratio of EBITDA to interest expense(4)............... 3.65 5.22 4.77
Ratio of earnings to fixed charges(5)................ 1.41 3.43 3.33
Gas transported and/or processed (TBtu/d)............ 4.4 7.0 7.9
NGLs production(MBbl/d).............................. 161 316 409
MARKET DATA:
Average NGLs price per gallon(6)..................... $.29 $.49 $.49
Average natural gas price per MMBtu(7)............... $1.95 $2.99 $2.99
BALANCE SHEET DATA (END OF PERIOD):
Total assets......................................... $3,655,728 $5,975,787 $5,989,262
Long-term debt....................................... -- -- $1,500,000
</TABLE>

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<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------ -----------------------
1997 1998 1999(1)(2) 1999(8) 2000(8)
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
HISTORICAL SEGMENT INFORMATION:
Operating revenues:
Natural gas.............................. $1,683,483 $1,497,901 $2,483,197 $ 847,782 $2,585,992
NGLs..................................... 423,680 309,380 1,365,577 396,042 1,607,882
Intersegment............................. (305,331) (222,961) (390,464) (134,980) (570,303)
---------- ---------- ---------- ---------- ----------
Total operating revenues.......... $1,801,832 $1,584,320 $3,458,310 $1,108,844 $3,623,571
========== ========== ========== ========== ==========
Margin:
Natural gas.............................. $ 334,129 $ 243,787 $ 459,843 $ 184,365 $ 482,066
NGLs..................................... (386) 2,404 33,170 8,169 26,468
---------- ---------- ---------- ---------- ----------
Total margin...................... $ 333,743 $ 246,191 $ 493,013 $ 192,534 $ 508,534
========== ========== ========== ========== ==========
EBITDA(3):
Natural gas.............................. $ 239,841 $ 175,835 $ 298,698 $ 116,464 $ 356,438
NGLs..................................... (386) 2,404 33,048 7,609 26,112
Corporate................................ (36,023) (44,946) (73,685) (30,759) (69,976)
---------- ---------- ---------- ---------- ----------
Total EBITDA...................... $ 203,432 $ 133,293 $ 258,061 $ 93,314 $ 312,574
========== ========== ========== ========== ==========
EBIT(3):
Natural gas.............................. $ 174,248 $ 102,365 $ 179,273 $ 62,852 $ 258,771
NGLs..................................... (386) 2,404 23,975 6,360 20,000
Corporate................................ (38,131) (47,049) (75,975) (31,904) (71,556)
---------- ---------- ---------- ---------- ----------
Total EBIT........................ $ 135,731 $ 57,720 $ 127,273 $ 37,308 $ 207,215
========== ========== ========== ========== ==========
Total assets:
Natural gas.............................. $1,505,111 $2,754,447 $4,833,083
NGLs..................................... 5,137 225,702 197,624
Corporate................................ 260,590 491,686 945,080
---------- ---------- ----------
Total assets...................... $1,770,838 $3,471,835 $5,975,787
========== ========== ==========
</TABLE>

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

(1) Includes $34.0 million of hedging losses recorded in total operating
revenues. Duke Energy commenced risk management activities associated with
its midstream natural gas business at the end of 1998. Activity for periods
prior to 1999 was not significant.

(2) Includes the results of operations of Union Pacific Fuels for the nine
months ended December 31, 1999. Union Pacific Fuels was acquired by the
Predecessor Company on March 31, 1999.

(3) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense, less
interest income. EBIT consists of income from continuing operations before
interest expense and income tax expense, less interest income. Neither
EBITDA nor EBIT is a measurement presented in accordance with generally
accepted accounting principles. You should not consider either measure in
isolation from or as a substitute for net income or cash flow measures
prepared in accordance with generally accepted accounting principles or as a
measure of our profitability or liquidity. EBITDA is included as a
supplemental disclosure because it may provide useful information regarding
our ability to service debt and to fund capital expenditures. However, not
all EBITDA may be available to service debt.

(4) The ratio of EBITDA to interest expense represents a ratio that provides an
investor with information as to our company's current ability to meet our
financing costs.

(5) For purposes of calculating the ratios of earnings to fixed charges,
"earnings" means income before extraordinary charges, plus income taxes and
fixed charges. Fixed charges include interest on indebtedness, amortization
of deferred financing costs, and that portion of lease expense that is
deemed to be representative of an interest factor. The ratio includes
amounts from our company, all of our majority-owned subsidiaries and our
proportionate share of distributed amounts from 50% owned investments that
are accounted for using the equity method.

(6) Based on index prices from the Mont Belvieu and Conway market hubs that are
weighted by our component and location mix for the periods indicated.

(7) Based on the NYMEX Henry Hub prices for the periods indicated.

(8) Includes $4.4 million of hedging gain and $59.2 million of hedging loss for
the six months ended June 30, 1999 and 2000, respectively.

S-11
<PAGE> 12

ADDITIONAL FINANCIAL AND OTHER DATA

The following table sets forth additional financial and other data of our
company. The additional financial and other data set forth in the table below
give effect to the Combination and the transfer to our company of additional
midstream natural gas assets acquired by Duke Energy or Phillips prior to
consummation of the Combination, which were completed on March 31, 2000 and to
the acquisition of Union Pacific Fuels, which occurred on March 31, 1999, as if
each occurred on January 1, 1995.

The additional financial and other data set forth in the table below should
not be considered to be indicative of:

- actual results that would have been realized had the Combination and the
acquisition of Union Pacific Fuels actually occurred on January 1, 1995;
or

- results of our future operations.

The data should be read in conjunction with the financial statements and related
notes and other financial information appearing elsewhere in this prospectus
supplement.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------------------------- -----------------------
1995 1996 1997 1998 1999(1) 1999(2) 2000(2)
---------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Total operating
revenues................ $2,413,871 $3,998,273 $4,769,072 $4,302,697 $5,574,580 $2,117,561 $4,223,158
Costs of natural gas and
petroleum products...... 1,729,278 2,976,059 3,798,465 3,527,533 4,554,776 1,684,884 3,539,618
OTHER DATA:
Gas transported and/or
processed (TBtu/d)...... 5.4 6.5 7.5 7.3 7.3 7.1 7.9
NGLs production(MBbl/d)... 277 313 358 373 400 372 409
MARKET DATA:
Average NGLs (price per
gallon)(3).............. $.29 $.39 $.35 $.26 $.34 $.29 $.49
Average natural gas (price
per MMBtu)(4)........... $1.64 $2.59 $2.59 $2.11 $2.27 $1.95 $2.99
</TABLE>

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

(1) Includes $34.0 million of losses from risk management activities recorded in
total operating revenues. Duke Energy commenced risk management activities
for its midstream natural gas business at the end of 1998. Activity for
periods prior to 1999 was not significant.

(2) Includes $4.4 million of hedging gain and $59.2 million of hedging loss for
the six months ended June 30, 1999 and 2000, respectively.

(3) Based on index prices from the Mont Belvieu and Conway market hubs that are
weighted by our component mix and location mix for the periods indicated.

(4) Based on the NYMEX Henry Hub prices for the periods indicated.

S-12
<PAGE> 13

USE OF PROCEEDS

We expect the net proceeds from the offering of the notes to be
approximately $1,486 million, after deducting discounts to the underwriters and
estimated expenses of the offering that we will pay. We expect to use the net
proceeds to repay a portion of our outstanding commercial paper. The proceeds of
the commercial paper were used to make one-time cash distributions of
approximately $1,525 million to Duke Energy and approximately $1,220 million to
Phillips in connection with the Combination and for working capital
requirements. At June 30, 2000, our outstanding commercial paper had maturity
dates ranging from one day to 60 days, with annual interest rates ranging from
6.7% to 7.2%.

CAPITALIZATION

The following table sets forth our short-term debt and total capitalization
as of June 30, 2000:

- on a historical basis; and

- on a pro forma basis giving effect to (1) the issuance of the notes
offered hereby and the application of the net proceeds therefrom and (2)
the issuance of an aggregate of $300 million of preferred membership
interests in our company to affiliates of Duke Energy and Phillips in
August 2000 and the application of the proceeds therefrom to repay short
term debt.

You should read the information below in conjunction with "Use of Proceeds,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our historical and pro forma financial statements and related
notes included elsewhere in this prospectus supplement.

<TABLE>
<CAPTION>
AS OF
JUNE 30, 2000
------------------------
HISTORICAL PRO FORMA
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Short-term debt(1).......................................... $2,585,290 $ 799,665
========== ==========
Long-term debt.............................................. $ -- $1,500,000
Equity:
Members' interest(2)...................................... 1,695,108 1,995,108
Retained earnings......................................... 627,220 626,320
Other comprehensive loss.................................. (1,117) (1,117)
---------- ----------
Total equity........................................... 2,321,211 2,620,311
---------- ----------
Total capitalization................................... $4,906,501 $4,919,976
========== ==========
</TABLE>

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

(1) Represents outstanding commercial paper issued to pay the distributions to
Duke Energy and Phillips.

(2) Members' interest represents Duke Energy's and Phillips' common and
preferred membership interests in our company.

S-13
<PAGE> 14

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following discussion details the material factors that affected our
historical and pro forma financial condition and results of operations in 1997,
1998 and 1999 and the six months ended June 30, 1999 and 2000. This discussion
should be read in conjunction with "Prospectus Supplement Summary -- Selected
Historical and Pro Forma Financial and Other Data," "-- Additional Financial and
Other Data" and the historical and pro forma financial statements, and, in each
case, the notes related thereto, included elsewhere in this prospectus
supplement.

Unless the context otherwise requires, the discussion of our business
contained in this section for periods ending on or prior to March 31, 2000
relates solely to the Predecessor Company on an historical basis and does not
give effect to the Combination, the transfer to our company of additional
midstream natural gas assets acquired by Duke Energy or Phillips prior to
consummation of the Combination or the transfer to our company of the general
partner of TEPPCO from Duke Energy.

OVERVIEW

We operate in the two principal business segments of the midstream natural
gas industry:

- natural gas gathering, processing, transportation and storage, from which
we generate revenues primarily by providing services such as compression,
treating and gathering, processing, local fractionation, transportation
of residue gas, storage and marketing. In 1999, approximately 72% of the
Predecessor Company's operating revenues and approximately 93% of the
Predecessor Company's gross margin were derived from this segment.

- NGLs fractionation, transportation, marketing and trading, from which we
generate revenues from transportation fees, market center fractionation
and the marketing and trading of NGLs. In 1999, approximately 28% of the
Predecessor Company's operating revenues and approximately 7% of the
Predecessor Company's gross margin were from this segment.

Our limited liability company agreement limits the scope of our business to
the midstream natural gas industry in the United States and Canada, the
marketing of NGLs in Mexico and the transportation, marketing and storage of
other petroleum products, unless otherwise approved by our board of directors.
This limitation in scope is not currently expected to materially impact the
results of our operations.

EFFECTS OF COMMODITY PRICES

In 1999, approximately 59% of the Predecessor Company's gross margin was
generated by arrangements that are commodity price sensitive and 41% of the
Predecessor Company's gross margin was generated by fee-based arrangements.
Because the gross margin of Phillips' midstream gas business is more heavily
weighted towards arrangements that are commodity price sensitive, as a result of
the Combination the portion of our gross margin generated by fee-based
arrangements has decreased. For example, in January 2000, after giving effect to
the Combination, approximately 28% of our gross margin was generated by
fee-based arrangements.

The midstream natural gas industry has been cyclical, with the operating
results of companies in the industry significantly affected by the prevailing
price of NGLs, which in turn generally is correlated to the price of crude oil.
Although the prevailing price of natural gas has less short-term significance to
our operating results than the price of NGLs, in the long term the growth of our
business depends on natural gas prices being at levels sufficient to provide
incentives and capital for producers to increase natural gas exploration and
production. In the past, the prices of NGLs and natural gas have been extremely
volatile.

S-14
<PAGE> 15

The following chart sets forth financial data for the Predecessor Company
and the weighted average price of NGLs for each of the five years ended December
31, 1999 and demonstrates the relationship of our EBITDA to NGL prices. The
chart below should not be viewed as indicating that the level of NGL prices is
the only factor affecting our results of operations. In addition to NGL prices,
our results of operations reflected in the chart below were primarily affected
by:

- fluctuations in raw natural gas volumes processed, including increases
resulting from our acquisitions and additions;

- the Predecessor Company's historical risk management activities; and

- gain/(loss) on the sale of assets.

[GRAPH]

Note: The weighted average NGL prices set forth in the chart above are
based on index prices from the Mont Belvieu and Conway market hubs
that are weighted by our component and location mix for the years
indicated.

The gas gathering and processing price environment deteriorated between
1996 and 1997 as prices for NGLs decreased and prices for natural gas increased
from 1996 levels. Increases in worldwide crude oil supply and production in 1998
drove a steep decline in crude oil prices. NGL prices also declined sharply in
1998 as a result of the correlation between crude oil and NGL pricing. Natural
gas prices also declined during 1998 principally due to mild weather.

The lower NGL and natural gas price environment experienced in 1998
prevailed during the first quarter of 1999. However, during the last three
quarters of 1999, NGL prices increased sharply as major crude oil exporting
countries agreed to maintain crude oil production at predetermined levels and
world demand for crude oil and NGLs increased. The lower crude oil and natural
gas prices in 1998 and early 1999 caused a significant reduction in the
exploration activities of U.S. producers, which in turn had a significant
negative effect on natural gas volumes gathered and processed in 1999.

During the first six months of 2000, the weighted average NGL price (based
on index prices from the Mont Belvieu and Conway market hubs that are weighted
by our component and location mix) was approximately $.49 per gallon. In the
near-term, we expect NGL prices to follow changes in crude oil prices generally,
which we believe will in large part be determined by the level of production
from major crude oil exporting countries and the demand generated by growth in
the world economy. In contrast, we believe that future natural gas prices will
be influenced by supply deliverability, the severity of winter weather and the
level of U.S. economic growth. We believe that weather will be the strongest
determinant of near-term natural gas prices. The price increases in crude oil,
NGLs and natural gas have spurred increased natural gas drilling activity. For
example, the number of actively drilling rigs in North America has increased by
approximately 57% from approximately 745 in June 1999 to more than 1,165 in

S-15
<PAGE> 16

June 2000. This drilling activity increase is expected to have a positive effect
on natural gas volumes gathered and processed in the near term.

EFFECTS OF OUR RAW NATURAL GAS SUPPLY ARRANGEMENTS

Our results are affected by the types of arrangements we use to purchase
raw natural gas. We obtain access to raw natural gas and provide our midstream
natural gas services principally under three types of contracts:

- Percentage-of-Proceeds Contracts -- Under these contracts (which also
include percentage-of-index contracts), we receive as our fee a
negotiated percentage of the residue natural gas and NGLs value derived
from our gathering and processing activities, with the producer retaining
the remainder of the value. These type of contracts permit us and the
producers to share proportionately in price changes. Under these
contracts, we share in both the increases and decreases in natural gas
prices and NGL prices. In December 1999, after giving effect to the
Combination, approximately 57% of our gross margin was generated from
percentage-of-proceeds or percentage-of-index contracts.

- Fee-Based Contracts -- Under these contracts we receive a set fee for
gathering, processing and/or treating raw natural gas. Our revenue stream
from these contracts is correlated with our level of gathering and
processing activity and is not directly dependent on commodity prices. In
December 1999, after giving effect to the Combination, approximately 25%
of our gross margin was generated from fee-based contracts.

- Keep-Whole Contracts -- Under these contracts we gather raw natural gas
from the producer for processing. After we process the raw natural gas,
we are obligated to return to the producer residue gas with a Btu content
equivalent to the Btu content of the raw natural gas gathered. As a
result of our processing, NGLs are extracted from the raw natural gas
resulting in a shrinkage in the Btu content of the natural gas. We market
the NGLs and purchase natural gas at market prices in order to return to
the producer residue gas with a Btu content equivalent to the Btu content
of the raw natural gas gathered. Accordingly, under these contracts, we
are exposed to increases in the price of natural gas and decreases in the
price of NGLs. In December 1999, after giving effect to the Combination,
approximately 15% of our gross margin was generated from keep-whole
contracts.

Our current mix of percentage-of-proceeds and percentage-of-index contracts
(where we are exposed to decreases in natural gas prices) and keep-whole
contracts (where we are exposed to increases in natural gas prices)
significantly mitigates our exposure to increases in natural gas prices, while
retaining our exposure to changes in NGL prices.

We prefer to enter into percentage-of-proceeds type supply contracts
(including percentage-of-index contracts). We believe this type of contract
provides the best alignment with our producers and represents the best
risk/reward profile for the capital we employ. Notwithstanding this preference,
we also recognize from a competitive viewpoint that we will need to offer
keep-whole contracts to attract certain supply to our systems. We also employ a
fee-type contract, particularly where there is treating and/or transportation
involved. Our contract mix and, accordingly, our exposure to natural gas and NGL
prices may change as a result of changes in producer preferences, our expansion
in regions where some types of contracts are more common and other market
factors.

Based upon the combined company's portfolio of supply contracts in 1999,
and excluding the effect of our commodities risk management program, an increase
of $.01 per gallon in the price of NGLs and $.10 per million Btu's in the
average price of natural gas throughout such period would have resulted in
changes in pre-tax net income of approximately $24 million and ($1) million,
respectively. See "-- Quantitative and Qualitative Disclosure About Market
Risks."

S-16
<PAGE> 17

OTHER FACTORS THAT HAVE SIGNIFICANTLY AFFECTED OUR RESULTS

Our results of operations also are correlated with increases and decreases
in the volume of raw natural gas that we put through our system, which we refer
to as throughput volume, and the percentage of capacity at which our processing
facilities operate, which we refer to as our asset utilization rate. Throughput
volumes and asset utilization rates generally are driven by production on a
regional basis and more broadly by demand for residue natural gas and NGLs.

Risk management, which has been directed by Duke Energy's centralized
program for controlling, managing and coordinating its management of risks, also
has affected our results of operations, particularly in 1999 and the first half
of 2000. Our 1999 and first half of 2000 results of operations include hedging
losses of $34.0 million and $59.2 million, respectively. Since the Combination,
we have directed our risk management activities independently of Duke Energy,
with goals, policies and procedures that are different from those of Duke
Energy. See "-- Quantitative and Qualitative Disclosure about Market Risks."

In addition to market factors and production, our results have been
affected by our acquisition strategy, including the timing of acquisitions and
our ability to integrate acquired operations and achieve operating synergies.

THE COMBINATION

On March 31, 2000, we combined the gas gathering, processing, marketing and
NGLs businesses of Duke Energy and Phillips. In connection with the Combination,
Duke Energy and Phillips transferred all of their respective interests in their
subsidiaries that conducted their midstream natural gas business to us. In
connection with the Combination, Duke Energy and Phillips also transferred to us
additional midstream natural gas assets acquired by Duke Energy or Phillips
prior to consummation of the Combination, including Mid-Continent gathering and
processing assets of Conoco and Mitchell Energy. The acquisition of the
Conoco/Mitchell assets is significant in that the assets acquired lie adjacent
to and between our current assets, providing future integration opportunities.
In addition, concurrently with the Combination, we obtained by transfer from
Duke Energy the general partner of TEPPCO. In exchange for the asset
contribution, Phillips received 30.3% of the member interests in our company,
with Duke Energy holding the remaining 69.7% of the outstanding member interests
in our company. In connection with the closing of the Combination, we borrowed
approximately $2.8 billion in the commercial paper market and made one-time cash
distributions (including reimbursements for acquisitions) of approximately $1.5
billion to Duke Energy and approximately $1.2 billion to Phillips. See
"-- Liquidity and Capital Resources." The Combination was accounted for as a
purchase of the Phillips midstream natural gas business.

The Combination was accounted for as a purchase business combination in
accordance with Accounting Principles Board Opinion (APB) No. 16, "Accounting
for Business Combinations." The Predecessor Company was the acquiror of
Phillips' midstream natural gas business in the Combination. The purchase price
allocation associated with the Phillips assets is preliminary. Currently there
are no pre-acquisition contingent liabilities reflected in the purchase price
allocation. The final purchase price allocation is subject to adjustment pending
gathering of additional information regarding certain pre-acquisition contingent
liabilities and obtaining appraisals. The effect of any pre-acquisition
contingencies is not expected to have a material effect on our operating
results, liquidity or financial condition.

COMBINED RESULTS OF OPERATIONS

The following is a discussion of the combined operating revenues and cost
of sales of our company giving effect to the Combination, the transfer to our
company of the midstream natural gas businesses acquired by Duke Energy and
Phillips prior to the consummation of the Combination and the acquisition of
Union Pacific Fuels as if each transaction occurred on January 1, 1995.

S-17
<PAGE> 18

This discussion should be read in conjunction with the historical and pro
forma financial statements and related notes and other financial information
appearing elsewhere in this prospectus supplement. The data on which this
discussion is based should not be considered indicative of:

- the actual results that would have been realized had the Combination and
the acquisition of Union Pacific Fuels actually occurred on January 1,
1995; or

- the results of our future operations.

SIX MONTHS ENDED JUNE 30, 2000 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1999

Operating Revenues. Operating revenues increased $2,106 million, or 99%,
from $2,117 million to $4,223 million. Of this increase, approximately $2,050
million is related to increased commodity prices as weighted average NGL prices,
based on our component product mix, were approximately $.20 per gallon higher
and natural gas prices were approximately $1.05 per million Btus higher.
Acquisitions and plant expansions contributed approximately $90 million to the
revenue increase. NGL production during the first six months ended June 30, 2000
increased approximately 11,000 barrels per day, or 3% from 391,000 barrels per
day to 402,000 barrels per day, and natural gas transported and/or processed
increased .9 trillion Btus per day, or 13%, from 7.1 trillion Btus per day to
8.0 trillion Btus per day. Included in the six months ended June 30, 2000
operating revenues is a $59.2 million loss attributable to hedging activity.

Cost of Sales. Costs of natural gas and petroleum products increased $1,855
million, or 110%, from $1,685 million to $3,540 million. This increase was
primarily due to the interaction of our gas and NGL purchase contracts with
higher commodity prices. Higher natural gas and NGLs throughput associated with
our acquisitions and plant expansions also increased product purchase costs.

1999 COMPARED WITH 1998

Operating Revenues. Operating revenues increased $1,271.9 million, or 30%,
from $4,302.7 million to $5,574.6 million. Of this increase, approximately
$1,100 million was due to increases in commodity prices, as weighted average NGL
prices, based on our component product mix, were approximately $.08 per gallon
higher and natural gas prices were approximately $.16 per million Btus higher.
Our acquisitions and plant expansions also contributed to this increase. NGLs
production during 1999 increased 27,000 barrels per day, or 7%, from 373,000
barrels per day to 400,000 barrels per day, and natural gas transported and/or
processed remained essentially unchanged at 7.3 trillion Btus per day. The
recovery of commodity prices during the last three quarters of 1999 encouraged
exploration and production activity, which positively affected existing
throughput volumes. Included in 1999 operating revenues is approximately $34.0
million of loss on hedging activity. There were no significant hedging
activities in 1998. See "-- Quantitative and Qualitative Disclosure About Market
Risks."

Cost of Sales. Costs of natural gas and petroleum products increased
$1,027.3 million, or 29%, from $3,527.5 million to $4,554.8 million. This
increase primarily was due to the interaction of our gas and NGL purchase
contracts with higher commodity prices.

1998 COMPARED WITH 1997

Operating Revenues. Operating revenues decreased $466.4 million, or 10%,
from $4,769.1 million to $4,302.7 million. Lower commodity prices resulted in an
approximately $800 million reduction of operating revenues, as weighted average
NGL prices, based on our component product mix, were approximately $.09 per
gallon lower and natural gas prices were unchanged. Partially offsetting this
decrease was approximately $22 million additional revenues attributable to our
fourth quarter 1997 acquisition of Highlands Gas Partners and approximately $300
million additional revenues attributable to our increased NGL trading and
marketing activities. Natural gas transported and/or processed decreased .2
trillion Btus per day, or 3%, from 7.5 trillion Btus per day to 7.3 trillion
Btus per day. This decrease was primarily the result of reduced exploration and
production activity caused by depressed commodity prices. This decrease was
offset by an increase in NGLs production of 15,000 barrels per day, or 4%, from
358,000 barrels per

S-18
<PAGE> 19

day to 373,000 barrels per day. NGLs production growth primarily was the result
of the Highlands Gas Partners acquisition and the restart of a processing
facility in the fourth quarter of 1997.

Cost of Sales. Cost of natural gas and petroleum products decreased $271.0
million, or 7%, from $3,798.5 million to $3,527.5 million. This decrease
primarily was due to declining NGL prices. Increased NGL trading and marketing
activity partially offset this decrease.

QUARTERLY COMBINED RESULTS

The following table sets forth unaudited combined financial and operating
data for our company on a quarterly basis for each of 1998, 1999 and the first
half of 2000.

<TABLE>
<CAPTION>
COMBINED
-------------------------------------------------------------------------------------------------
1998 1999 2000
------------------------------------- ------------------------------------- -----------------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH FIRST SECOND
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total operating
revenues.............. $1,113 $1,143 $1,095 $952 $959 $1,158 $1,597 $1,861 $2,051 $2,172
Costs of natural gas and
petroleum products.... 902 951 900 775 762 923 1,313 1,557 1,703 1,837
Average NGL price (per
gallon)(1)............ .28 .26 .20 .22 .22 .30 .39 .41 .50 .47
</TABLE>

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

(1) Based on index prices from the Mont Belvieu and Conway market hubs that are
weighted by our component and location mix for the periods indicated.

HISTORICAL RESULTS OF OPERATIONS

The following is a discussion of our historical results of operations. The
discussion for periods ending on or prior to March 31, 2000 relates solely to
the Predecessor Company and does not give effect to the Combination, the
transfer to our company of additional midstream natural assets acquired by Duke
Energy or Phillips prior to consummation of the Combination or the transfer to
our company of the general partner of TEPPCO from Duke Energy.

SIX MONTHS ENDED JUNE 30, 2000 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1999

Operating Revenues. Operating revenues increased $2,514.8 million, or 227%
from $1,108.8 million to $3,623.6 million. Operating revenues from the sale of
natural gas and petroleum products accounted for $3,542.8 million of the total
and $2,509.9 million of the increase. Of this increase, approximately $600.1
million is related to the addition of the Phillips' midstream natural gas
business to our operations in the Combination on March 31, 2000, and
approximately $425 million is related to the March 31, 1999 acquisition of Union
Pacific Fuels. Increased NGL trading and marketing activity also contributed to
the increase. NGL production during the six months ended June 30, 2000 increased
155,200 barrels per day, or 96%, from 161,100 barrels per day to 316,300 barrels
per day, and natural gas transported and/or processed increased 2.6 trillion
Btus per day, or 59%, from 4.4 trillion Btus per day to 7.0 trillion Btus. Of
the 155,200 barrels per day increase, the addition of the Phillips' midstream
natural gas business in the Combination contributed approximately 82,900 barrels
per day, and the Union Pacific Fuels acquisition contributed approximately
50,300 barrels per day. The combination of our Wilcox plant expansion,
completion of our Mobile Bay Plant and the acquisition of Koch's South Texas
assets accounted for the remainder of the increase. Of the 2.6 trillion Btus per
day increase, the addition of the Phillips' midstream natural gas business in
the Combination contributed approximately 1.0 trillion Btus per day, and the
Union Pacific Fuels acquisition contributed approximately 1.0 trillion Btus per
day. The combination of other acquisitions, plant expansions and completions
accounted for the balance of the increase.

Commodity prices significantly contributed to higher revenues. Weighted
average NGL prices, based on our component product mix, were approximately $.20
per gallon higher and natural gas prices were approximately $1.04 per million
Btus higher for the first six months of 2000. These price increases yielded

S-19
<PAGE> 20

average prices of $.49 per gallon of NGLs and $2.99 per million Btus of natural
gas, respectively, as compared with $.29 per gallon and $1.95 per million Btus
for the first six months of 1999. Revenues associated with gathering,
transportation, storage, processing fees and other increased $4.7 million, or
6%, from $76.0 million to $80.7 million, mainly as a result of the Union Pacific
Fuels acquisition. A $59.2 million hedging loss in the first six months of 2000
partially offset total operating revenue increases. See "--Quantitative and
Qualitative Disclosure About Market Risks."

Costs and Expenses. Costs of natural gas and petroleum products increased
$2,198.7 million, or 240%, from $916.3 million to $3,115 million. This increase
was due to the addition of the Phillips' midstream natural gas business in the
Combination (approximately $450.4 million), the Union Pacific Fuels acquisition
(approximately $340 million),and the interaction of our natural gas and NGL
purchase contracts with higher commodity prices and increased trading and
marketing activity.

Operating and maintenance expenses increased $61.7 million, or 78%, from
$78.7 million to $140.4 million. Of this increase, approximately $41 million is
related to the addition of the Phillips' midstream natural gas business in the
Combination and approximately $13 million is related to the Union Pacific Fuels
acquisition. General and administrative expenses increased $39.2 million, or
127%, from $30.8 million to $70 million. Of this increase, $12.3 million was due
to increased allocated corporate overhead from Duke Energy as a result of our
company's growth. The remainder was associated with increased activity resulting
from the addition of the Phillips' midstream natural gas business in the
Combination, the Union Pacific Fuels acquisition and increased fiscal year 2000
incentive compensation accruals.

Depreciation and amortization increased $49.4 million, or 88%, from $56.0
million to $105.4 million. Of this increase, $26.1 million was due to the
addition of the Phillips' midstream natural gas business in the Combination and
$15.4 million was due to the Union Pacific Fuels acquisition. The remainder was
due to ongoing capital expenditures for well connections, facility
maintenance/enhancements and acquisitions.

Equity Earnings. Equity earning of unconsolidated affiliates increased $4.4
million, or 43%, from $10.3 million to $14.7 million. This increase was largely
due to interests in joint ventures and partnerships acquired from Union Pacific
Fuels and the acquisition of the general partnership interest in TEPPCO as of
March 31, 2000.

Interest. Interest expense increased $34.4 million, or 135%, from $25.5
million to $59.9 million. This increase is primarily the result of the issuance
of commercial paper to fund the distribution paid to Duke Energy and Phillips in
the Combination.

Income Taxes. At March 31, 2000, the Predecessor Company converted to a
limited liability company which is a pass-through entity for income tax
purposes. As a result, substantially all of the Predecessor Company's existing
net deferred tax liability ($327 million) was eliminated and a corresponding
income tax benefit was recorded.

Net Income. Net income increased $447.9 million from $6.2 million to $454.1
million. This increase was largely the result of the tax benefit recognition
discussed above, the addition of the Phillip's midstream natural gas business in
the Combination and the Union Pacific Fuels acquisition. Higher NGL prices
contributed significantly to this increase and were partially offset by higher
natural gas prices. A $59.2 million pre-tax loss from hedging activities
experienced during the first six months of 2000 partially offset the increase.

EBITDA. In addition to the GAAP measures described above, we also use the
non-GAAP measure of EBITDA. EBITDA is a measure used to provide information
regarding our ability to cover fixed charges such as interest, taxes, dividends
and capital expenditures. In addition, EBITDA provides a comparable measure to
evaluate our performance relative to that of our competitors by eliminating the
capitalization structure and depreciation charges, which may vary significantly
within our industry. Although the GAAP financial statement measure of net income
or loss, in total and by segment, is indicative of our profitability, net income
does not necessarily reflect our ability to fund our fixed charges on a periodic
basis. We therefore use GAAP and non-GAAP measures in evaluating our overall
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performance as well as that of our related segments. In addition, we use both
types of measures to evaluate our performance relative to other companies within
our industry.

EBITDA for the natural gas gathering, processing, transportation and
storage segment increased $239.9 million, or 206%, from $116.5 million to $356.4
million. Of this increase, approximately $113.6 was due to the addition of the
Phillips' midstream natural gas business in the Combination, approximately $56
million was due to the acquisition of Union Pacific Fuels, and approximately $90
million due to a $.20 per gallon increase in average NGL prices. Additional
increases were attributable to the combination of our Wilcox plant expansion,
completion of our Mobile Bay plant, the acquisition of Koch's South Texas
assets, and the acquisition of the general partnership interest in TEPPCO. These
benefits were offset by a $63.6 million decrease from hedging activities ($59.2
million loss in the first six months of 2000 compared to a $4.4 million gain in
the comparable period of 1999) and approximately $16 million due to a $1.04 per
million Btu increase in natural gas prices.

EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $18.5 million from $7.6 million to $26.1 million due primarily
to NGL trading and marketing activity and the acquisition of Union Pacific
Fuels.

1999 COMPARED WITH 1998

Operating Revenues. Operating revenues increased $1,874.0 million, or 118%,
from $1,584.3 million to $3,458.3 million. Operating revenues from the sale of
natural gas and petroleum products accounted for $3,310.3 million of the total
and $1,841.2 million of the increase. Of this increase, approximately $1.0
billion was attributable to the March 31, 1999 acquisition of Union Pacific
Fuels. Increased NGL trading and marketing activity associated with the Union
Pacific Fuels acquisition also contributed to the increase. NGL production
during 1999 increased 82,000 barrels per day, or 75%, from 110,000 barrels per
day to 192,000 barrels per day. Of the 82,000 barrels per day increase, the
Union Pacific Fuels acquisition contributed 71,000 barrels per day, with the
combination of our Wilcox plant expansion, completion of our Mobile Bay Plant
and the acquisition of Koch's South Texas assets accounting for the remainder of
the increase. Raw natural gas transported and/or processed increased 1.5
trillion Btus per day, or 42%, from 3.6 trillion Btus per day to 5.1 trillion
Btus per day. The Union Pacific Fuels acquisition accounted for 1.4 trillion
Btus per day of the natural gas increase.

Commodity prices also contributed to higher revenues. Weighted average NGL
prices, based on our component product mix, were approximately $.08 per gallon
higher and natural gas prices were approximately $.16 per million Btus higher
for 1999, yielding prices of $.34 and $2.27, respectively, as compared with $.26
and $2.11 in 1998. Revenues associated with gathering, transportation, storage,
processing fees and other increased $32.8 million, or 28%, from $115.2 million
to $148.0 million principally as a result of the Union Pacific Fuels
acquisition. Total operating revenue increases were offset by a $34.0 million
hedging loss in 1999. See "-- Quantitative and Qualitative Disclosure About
Market Risks."

Costs and Expenses. Costs of natural gas and petroleum products increased
$1,627.2 million, or 122%, from $1,338.1 million to $2,965.3 million. This
increase was due primarily to the Union Pacific Fuels acquisition ($800
million), increased NGL trading and marketing activity and the interaction of
our natural gas and NGL purchase contracts with higher commodity prices.

Operating and maintenance expenses increased $67.8 million, or 60%, from
$113.6 million to $181.4 million. Of this increase, approximately $65.0 million
was due to the Union Pacific Fuels acquisition. General and administrative
expenses increased $28.7 million, or 64%, from $45.0 million to $73.7 million.
This increase was due to a $7.0 million increase in allocated corporate overhead
from our parent, Duke Energy, and increases resulting from the Union Pacific
Fuels acquisition.

Depreciation and amortization increased $55.2 million, or 73%, from $75.6
million to $130.8 million. Of this increase, $45.2 million was due to the Union
Pacific Fuels acquisition and the remainder was due to ongoing capital
expenditures for well connections, facility maintenance/enhancements and
acquisitions.

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Sale of Assets. Net (gain) loss on sales of assets decreased $36.2 million,
from a $33.8 million gain to a $2.4 million loss from 1998 to 1999. This
decrease was primarily the result of a $38.0 million gain recognized in 1998 on
the sale of two fractionators in Weld County, Colorado.

Equity Earnings. Equity earnings of unconsolidated affiliates increased
$10.7 million, or 91%, from $11.8 million to $22.5 million. This increase was
largely due to interests in joint ventures and partnerships acquired from Union
Pacific Fuels in 1999.

Interest. Interest expense of $52.9 million for 1999 remained almost
unchanged from 1998 and was principally related to interest on notes due to Duke
Energy.

Net Income. Net income increased $41.3 million from $2.0 million to $43.3
million. This increase was largely the result of the acquisition of Union
Pacific Fuels and higher average NGL prices experienced during 1999. The benefit
of higher NGL prices was partially offset by higher natural gas prices. The
increase in net income was largely offset by a pre-tax gain of approximately
$38.0 million recognized on the sale of our Weld County fractionators in 1998
and a $34.0 million loss on hedging activity in 1999.

EBITDA. EBITDA for the natural gas gathering, processing, transportation
and storage segment increased $122.9 million from $175.8 million to $298.7
million. Of the increase, approximately $110 million was due to the acquisition
of Union Pacific Fuels and $80.0 million was due to $.08 per gallon higher NGL
prices. Additional increases were recognized with the combination of our Wilcox
plant expansion, completion of our Mobile Bay Plant and the acquisition of
Koch's South Texas assets. These increases were offset by a $38.0 million gain
recognized in 1998 on the sale of the Weld County fractionators, hedging losses
in 1999 of $34.0 million, an approximately $5 million decrease due to $.16 per
million BTU increase in gas prices and a $7.0 million increase in allocated
corporate overhead from our parent, Duke Energy.

EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $30.6 million from $2.4 million to $33.0 million due primarily
to the acquisition of Union Pacific Fuels.

1998 COMPARED WITH 1997

Operating Revenues. Operating revenues decreased $217.5 million, or 12%,
from $1,801.8 million to $1,584.3 million. Operating revenues from the sale of
natural gas and petroleum products decreased $230.9 million, or 14%, from
$1,700.0 million to $1,469.1 million. This decrease was largely due to commodity
prices, as weighted average NGLs prices, based on our component product mix,
were approximately $.09 per gallon lower and natural gas prices were
approximately $.48 per MMBtu lower for 1998, yielding prices of $.26 and $2.11,
respectively, as compared with $.35 and $2.59 in 1997. This NGL price decline
was partially offset by an increase in NGL production during 1998 of 2,000
barrels per day, or 2%, from 108,000 barrels per day to 110,000 barrels per day,
and by an increase in natural gas gathered, transported and/or processed of .2
trillion Btus per day, or 6%, from 3.4 trillion Btus per day to 3.6 trillion
Btus per day, due to increased production on existing facilities. Revenues
associated with gathering, transportation, storage, processing fees and other
increased $13.4 million, or 13%, from $101.8 million to $115.2 million. This
increase was principally the result of increased volumes.

Costs and Expenses. Costs of natural gas and petroleum products decreased
$130.0 million, or 9%, from $1,468.1 million to $1,338.1 million. This decrease
was primarily due to declining NGL prices. The NGL price decline was partially
offset by increases in system throughput volumes.

Operating and maintenance expenses increased $9.3 million, or 9%, from
$104.3 million to $113.6 million. This increase was primarily due to higher
property tax accruals associated with property additions and other inflationary
factors. General and administrative expenses increased $8.9 million, or 25%,
from $36.0 million to $44.9 million. This increase was due primarily to an
increase in the incentive bonus accrual and internal growth.

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Depreciation and amortization increased $7.9 million, or 12%, from $67.7
million to $75.6 million. This increase was primarily due to ongoing capital
expenditures for well connections, facility maintenance/enhancements and
acquisitions.

Sales of Assets. Net (gain) loss on sales of assets increased $33.6
million, from a $.2 million gain to a $33.8 million gain from 1997 to 1998. This
increase was primarily due to a $38.0 million gain recognized in March 1998 on
the sale of the Weld County fractionators.

Equity Earnings. Equity earnings of unconsolidated affiliates increased
$2.0 million, or 20%, from $9.8 million to $11.8 million. This increase was
largely due to increased earnings from Dauphin Island Gathering and Main Pass
Oil in the offshore region.

Interest. Interest expense increased $1.3 million, or 3%, from $51.1
million to $52.4 million. Interest expense reflects interest on notes due to
affiliated companies.

Net Income. Net income decreased $49.2 million, or 96%, from $51.2 million
to $2.0 million. This decrease was largely the result of substantially lower
commodity prices. A pre-tax gain of approximately $38.0 million recognized on
the sale of our Weld County fractionators in March 1998 partially offset the
impact of the sharp NGL price decline.

EBITDA. EBITDA for the natural gas gathering, processing, transportation
and storage segment decreased $64.0 million from $239.8 million to $175.8
million. Of the decrease, approximately $80 million was due to $.09 per gallon
lower NGL prices and approximately $18 million was due to increased operating
and general and administrative expenses resulting from higher property tax
accruals associated with property additions, an increase in the incentive bonus
accrual and internal growth. These decreases were partially offset by a $38.0
million gain recognized in March 1998 on the sale of the Weld County
fractionators.

EBITDA for the NGLs fractionation, transportation, marketing and trading
segment increased $2.8 million from $(.4) million to $2.4 million due to
increased trading and marketing activity.

ENVIRONMENTAL CONSIDERATIONS

Environmental expenditures are expensed or capitalized as appropriate,
depending upon the future economic benefit. Historically these expenditures have
been between $5 million and $15 million annually except for those environmental
liabilities identified with the acquisition of Union Pacific Fuels of
approximately $63 million. The Union Pacific Fuels environmental liabilities
associated with soil and groundwater contamination were transferred to a third
party at a cost of approximately $48 million.

The outlook for environmental spending, both capitalized and expensed, is
not expected to change materially from historical levels of $5 to $15 million
annually.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY PRIOR TO THE COMBINATION

The Predecessor Company's capital investments and acquisitions were
financed by cash flow from operations and non-interest bearing advances from
Duke Energy or its subsidiaries under various arrangements. Under Duke Energy's
centralized cash management system, Duke Energy deposited sufficient funds in
our bank accounts for us to meet our daily obligations and withdrew excess funds
from those accounts. Advances were offset by cash provided by operations to
yield net advances from Duke Energy which were included in the historical
consolidated balance sheets and statements of cash flows of the Predecessor
Company. In 1999, the Predecessor Company had notes to and advances from Duke
Energy which were terminated in connection with the Combination.

FINANCING TRANSACTIONS IN CONNECTION WITH THE COMBINATION

In connection with the Combination, all advances from Duke Energy were
capitalized to equity.

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On March 31, 2000, we entered into a $2.8 billion credit facility with
several financial institutions. The credit facility will be used as the
liquidity backstop to support a commercial paper program. On April 3, 2000 we
borrowed approximately $2.8 billion in the commercial paper market to fund the
one-time cash distributions (including reimbursements for acquisitions) of
approximately $1.5 billion to Duke Energy and approximately $1.2 billion to
Phillips and to cover working capital requirements. At June 30, 2000 we had $2.6
billion in outstanding commercial paper, with maturities ranging from one day to
60 days and annual interest rates ranging from 6.71% and 7.2%. At no time will
the amount of our outstanding commercial paper exceed the available amount under
the credit facility. The credit facility matures on March 30, 2001 and
borrowings bear interest at a rate equal to, at our option, either (1) LIBOR
plus .50% per year for the first 90 days following the closing of the credit
facility and LIBOR plus .625% per year thereafter or (2) the higher of (a) the
Bank of America prime rate and (b) the Federal Funds rate plus .50% per year.

The amount available under the bank credit facility and corresponding
commercial paper program will be reduced by the amount, if any, of long-term
debt we may issue, including the notes offered hereby, but we intend that the
credit facility will not be reduced to below $1.0 billion. In the future, our
debt levels will vary depending on our liquidity needs, capital expenditures and
cash flow.

Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program and credit facilities, will be sufficient to
enable us to meet our current and anticipated cash operating requirements and
working capital needs for the next year. Actual capital requirements, however,
may change, particularly as a result of any acquisitions that we may make. Our
ability to meet current and anticipated operating requirements will depend on
our future performance.

PREFERRED FINANCING

In August 2000, we issued $300 million of preferred member interests to
affiliates of Duke Energy and Phillips. The proceeds from this financing were
used to repay a portion of our outstanding commercial paper. The preferred
member interests are entitled to cumulative preferential distributions of 9.5%
per annum payable, unless deferred, semi-annually. We have the right to defer
payments of preferential distributions on the preferred member interests, other
than certain tax distributions, at any time and from time to time, for up to 10
consecutive semi-annual periods. Deferred preferred distributions will accrue
additional amounts based on the preferential distribution rate (plus 0.5% per
annum) to the date of payment. The preferred member interests, together with all
accrued and unpaid preferential distributions, must be redeemed and paid on the
earlier of the thirtieth anniversary date of issuance and consummation of an
initial public offering of equity securities.

CAPITAL EXPENDITURES

Our capital expenditures consist of expenditures for acquisitions and
construction of additional gathering systems, processing plants, fractionators
and other facilities and infrastructure in addition to well connections and
repairs and maintenance of our existing facilities. Our capital expenditure
budget for well connections and repair and maintenance of our existing
facilities in 2000 is approximately $175 million, of which approximately $115
million was spent in the six months ended June 30, 2000.

On March 31, 2000, we acquired gathering and processing assets located in
central Oklahoma from Conoco and Mitchell Energy. We paid cash of $99.5 million
and exchanged our interest in certain gathering and marketing joint ventures
located in southeast Texas having a total fair value of approximately $42
million as consideration for these assets.

Our level of capital expenditures for acquisitions and construction depends
on many factors, including industry conditions, the availability of attractive
acquisition candidates and construction projects, the level of commodity prices
and competition. We expect to finance our capital expenditures with our cash on
hand, cash flow from operations and borrowings available under our commercial
paper program, our credit facilities or other available sources of financing.
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CASH FLOWS

Net cash provided by operating activities for the six months ended June 30,
2000 improved to $324.7 million from $131.2 million for the same period in 1999,
primarily due to higher commodity prices and acquisitions. Net cash used in
investing activities was $189.3 million for the six months ended June 30, 2000
compared to $1,543.1 million for the same period in 1999. Acquisitions of the
Conoco and Mitchell Energy assets in 2000 and the Union Pacific Fuels assets in
1999 were the primary uses of the invested cash. The net cash used in investing
activities was financed through operating activities, advances from Duke Energy
and proceeds from the issuance of short-term debt.

Net cash provided by operating activities for the Predecessor Company in
1999 improved to $173.1 million from $40.4 million in 1998, primarily due to
higher commodity prices and acquisitions. Net cash used in investing activities
by the Predecessor Company was $1,571.4 million for 1999 compared to $203.6
million for 1998, of which $1,456.5 million was used for acquisitions and the
remainder was used principally for capital expenditures. The net cash used in
investing activities was financed through operating activities, advances from
Duke Energy and proceeds from the issuance of short-term debt.

Net cash provided by operating activities for the Predecessor Company was
$40.4 million for 1998 compared to $173.4 million for 1997. This decrease was
primarily due to the reduction of trade accounts payable to producers for the
purchase of raw natural gas at purchase prices lower than those in 1997. Net
cash used in investing activities by the Predecessor Company in 1998 increased
to $203.6 million from $138.0 million in 1997. In 1998, $185.5 million was used
for capital expenditures and $84.9 million was used for investments in
affiliates. The net cash used in investing activities was provided by operating
activities and advances from Duke Energy.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

COMMODITY PRICE RISK

We are subject to significant risks due to fluctuations in commodity
prices, primarily with respect to the prices of NGLs that we own as a result of
our processing activities. Based upon the Predecessor Company's portfolio of
supply contracts in 1999, without giving effect to hedging activities that would
reduce the impact of commodity price decreases, a decrease of $.01 per gallon in
the price of NGLs and $.10 per million Btus in the average price of natural gas
throughout 1999 would have resulted in changes in pre-tax net income of
approximately $(15 million) and $5 million, respectively. Based upon the
combined company's portfolio of supply contracts in 1999, and excluding the
effects of our commodities risk management program, similar commodities price
changes in 1999 would have resulted in changes in pre-tax net income of
approximately $(24 million) and $1 million, respectively.

Commodity derivatives such as futures and swaps are available to reduce
such exposure to fluctuations in commodity prices. Gains and losses related to
commodity derivatives are recognized in income when the underlying hedged
physical transaction closes, and such gains and losses are included in sales of
natural gas and petroleum products in our statement of income.

Natural gas and crude oil futures, which are used to hedge NGLs prices,
involve the buying and selling of natural gas and crude oil for future delivery
at a fixed price. Over-the-counter swap agreements require us to receive or make
payments on the difference between a specified price and the actual price of
natural gas or crude oil.

Historically, the Predecessor Company's commodity price risk was managed by
Duke Energy's centralized program for controlling, managing and coordinating its
risk management activities. Under this program, the Predecessor Company used
futures and swaps to manage margins on offsetting fixed-price purchase or sale
commitments for physical quantities of natural gas and NGLs. Historically,
futures and swaps conducted through Duke Energy were handled through Duke Energy
Trading and Marketing, LLC, a partnership in which Duke Energy owns a 60%
interest. Under this arrangement, the Predecessor Company did not experience
margin requirements.

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At December 31, 1998 and 1999 the Predecessor Company (through Duke Energy)
had outstanding futures and swaps for an absolute notional contract quantity of
10.92 and 7.8 Bcf of natural gas and an absolute notional contract quantity of
59,000 and 32,764,000 barrels of crude oil, respectively, both of which were
intended to offset the risk of price fluctuations under fixed-price commitments
for delivering and purchasing natural gas and NGLs, respectively. The gains,
losses and costs related to those financial instruments that qualify as a hedge
are not recognized until the underlying physical transaction occurs. At December
31, 1998 and 1999, the Predecessor Company had current unrecognized net gains
(losses) of $1.8 million and $(63.5 million), respectively, related to commodity
instruments. All unrecognized gains and losses at March 31, 2000, the date of
the Combination, remain with Duke Energy and will not have an impact on our
company's future earnings.

Losses relating to hedging with commodity derivatives included in the
Predecessor Company's statement of income equaled $34.0 million for 1999. There
were no corresponding losses in 1997 or 1998. For the six months ended June 30,
1999 and 2000, we recorded a hedging gain of $4.4 million and a hedging loss of
$59.2 million, respectively.

After the Combination, we began directing our risk management activities
independently of Duke Energy.

We use commodity-based derivative contracts to reduce the risk in our
overall earnings and cash flow with the primary goals of:

- maintaining minimum cash flow to fund debt service, dividends, and
maintenance type capital projects;

- avoiding disruption of our growth capital and value creation process; and

- retaining a high percentage of the potential upside relating to commodity
price increases.

We implemented a risk management policy that provides guidelines for
entering into contractual arrangements to manage our commodity price exposure.
Our risk management committee has ongoing responsibility for the content of this
policy and has principal oversight responsibility for compliance with the policy
framework by ensuring proper procedures and controls are in place.

In general, we seek to provide downside protection to our business
activities while retaining most of the upside potential by using floors and
other similar hedging structures. These structures will typically require the
payment of a premium to protect the downside while retaining exposure to the
upside. Historically, NGLs and related commodity products have shown a mean
reverting tendency to long term average prices, which implies that supply and
demand for products balance over cycles. Therefore, we may choose to forego
price upside in favor of a known, hedged cash flow position as prices rise
significantly above historical levels and depending upon existing market
drivers.

An active forward market for hedging of NGL products is not normally
available for hedging a significant amount of our NGL production beyond a one to
three month time horizon. With an anticipated hedging horizon of up to 12
months, crude oil derivatives, which historically have had a high correlation
with NGL prices, will typically be the mechanism used for longer-term price risk
management.

As of March 31, 2000, the existing commodity positions under the Duke
Energy centralized program were transferred to Duke Energy. In establishing our
initial independent commodity risk management position on April 1, 2000, we
acquired a portion of Duke Energy's existing commodity derivatives held for
non-trading purposes. The absolute notional contract quantity of the positions
acquired was 4,607,000 barrels of crude oil. Such positions were acquired at
market value.

INTEREST RATE RISK

Prior to the Combination, we had no material interest rate risk associated
with debt used to finance our operations due to limited third party borrowings.
As of June 30, 2000, we had approximately $2.6 billion outstanding under a
commercial paper program. As a result, we are exposed to market risks
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related to changes in interest rates. In the future, we intend to manage our
interest rate exposure using a mix of fixed and floating interest rate debt.
Assuming none of our outstanding commercial paper is refinanced with long-term
fixed rate debt, an increase of .5% in interest rates would result in an
increase in annual interest expense of approximately $13.0 million.

As of June 30, 2000, we had in place $1,150 million notional amount of
treasury rate locks and interest rate swaps to hedge interest rate risk
associated with this offering.

FOREIGN CURRENCY RISK

Currently we have no material foreign currency exposure.

ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). SFAS 133 establishes standards for
derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If certain conditions are met, a derivative may be
specifically designated as:

- a hedge of the exposure to changes in the fair value of a recognized
asset or liability or an unrecognized firm commitment;

- a hedge of the exposure to variable cash flows of a forecasted
transaction; or

- a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale
security, or a foreign-currency-denominated forecasted transaction.

The accounting for changes in the fair value of a derivative (gains and
losses) depends on the intended use of the derivative and the resulting
designation. We are required to adopt SFAS 133 on January 1, 2001. We have not
completed the process of evaluating the impact that will result from adopting
SFAS 133.

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BUSINESS

OUR BUSINESS

- natural gas gathering, processing, transportation, marketing and storage;
and

- NGL fractionation, transportation, marketing and trading.

- we gathered and/or transported an average of approximately 7.3 billion
cubic feet per day of raw natural gas;

- we produced an average of approximately 400,000 barrels per day of NGLs;
and

- we marketed and traded an average of approximately 486,000 barrels per
day of NGLs.

We sell NGLs to a variety of customers ranging from large, multi-national
petrochemical and refining companies to small regional retail propane
distributors. Substantially all of our NGL sales are made at market-based
prices, including approximately 40% of our NGL production that is committed to
Phillips under an existing 15-year contract. We market approximately 370,000
barrels per day of NGLs processed at our owned and operated plants and 40,000
barrels per day of NGLs processed at third-party operated facilities and trade
approximately 75,000 barrels per day of NGLs at market centers.

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On March 31, 2000, we obtained by transfer from Duke Energy the general
partner of TEPPCO, a publicly traded limited partnership which owns and operates
a network of pipelines for refined products and crude oil. The general partner
is responsible for the management and operations of TEPPCO. We believe that our
ownership of the general partner of TEPPCO improves our business position in the
transportation sector of the midstream natural gas industry and provides
additional flexibility in pursuing our disciplined acquisition strategy by
providing an alternative acquisition vehicle. It also provides us with an
opportunity to sell appropriate assets currently held by our company to TEPPCO.
Through our ownership of the general partner of TEPPCO we have the right to
receive from TEPPCO incentive cash distributions in addition to a 2% share of
distributions based on our general partner interest. At TEPPCO's 1999 per unit
distribution level, the general partner:

- receives approximately 14% of the cash distributed by TEPPCO to its
partners, which consists of 12% from the incentive cash distribution
and 2% from the general partner interest; and

- under the incentive cash distribution provisions, receives 50% of
any increase in TEPPCO's per unit cash distributions.

On July 21, 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield
Company's ownership interests in a 500-mile crude oil pipeline that extends from
a marine terminal at Freeport to Cushing, a 416-mile crude oil pipeline that
extends from Jal to Cushing, a 400-mile crude oil pipeline that extends from
West Texas to Houston, crude oil terminal facilities in Midland, Cushing and the
Houston area and receipt and delivery pipelines centered around Midland.

INDUSTRY OVERVIEW

The midstream natural gas industry in North America is comprised of
approximately 150 companies that process approximately 45 billion cubic feet per
day of raw natural gas and produce approximately 1.9 million barrels per day of
NGLs. The industry generally is characterized by regional competition based on
the proximity of gathering systems and processing plants to natural gas
producing wells.

Demand for natural gas in North America has grown significantly in recent
years. We believe that demand will continue to increase and will be driven
primarily by the growth of natural gas-fired electric generation. According to
the EIA Report, U.S. demand for natural gas is expected to increase from 22
trillion cubic feet in 1999 to 32 trillion cubic feet in 2020. We believe that
oil and natural gas producers in North America will respond to increased demand
by focusing their exploration and drilling efforts on basins where pipeline and
processing capacity has been, or is being, built and where there is sufficient
capacity to meet the needs of high demand markets. We have a strong presence and
significant capacity in several of these areas (including Onshore Gulf of Mexico
and Rocky Mountains, where, according to the Oil and Gas Journal's "1999
Worldwide Gas Processing Report," we are among the three largest midstream
natural gas companies based on volumes of natural gas gathered and processed or
volumes of NGLs produced) that, according to the EIA Report, are forecasted to
have significant growth in production between now and 2020. This growth in
production, which is expected to be 2.31 trillion cubic feet in Rocky Mountain
region and 1.71 trillion cubic feet in Onshore Gulf of Mexico region by 2020,
should provide us with opportunities to increase our throughput volumes and
asset utilization.

The midstream natural gas industry has experienced significant
consolidation since the mid-1990s. We believe the following factors have
contributed to this consolidation:

- significant economies of scale resulting from improved operating
efficiencies, throughput volumes and asset utilization rates that can be
achieved by strategically growing operations;

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- decisions by transmission pipelines and by exploration and production
companies to divest their gathering, processing and marketing activities
and concentrate their businesses on gas transmission and on exploration
and production; and

- technological improvements.

OUR BUSINESS STRATEGY

- Increase our presence in high growth production areas. According to the
EIA Report, production from areas such as Western Canada, Onshore Gulf of
Mexico, Rocky Mountains and Offshore Gulf of Mexico is expected to
increase significantly to meet anticipated increases in demand for
natural gas in North America. We intend to use our strategic asset base
in these growth areas and our leading position in the midstream natural
gas industry as a platform for future growth in these areas. We plan to
increase our operations in these areas by following a disciplined
acquisition strategy, and by expanding existing infrastructure and
constructing new gathering lines and processing facilities.

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with a complementary base of assets from which to further extract operating
efficiencies and cost reductions, while continuing to provide superior customer
service.

NATURAL GAS GATHERING, PROCESSING, TRANSPORTATION, MARKETING AND STORAGE

OVERVIEW

At March 31, 2000, our raw natural gas gathering and processing operations
consisted of:

- approximately 57,000 miles of gathering pipe, with connections to
approximately 38,000 active producing wells; and

- 70 owned and operated processing plants and ownership interests in 13
additional third-party operated plants, with a combined processing
capacity of approximately 7.9 billion cubic feet per day.

In 1999, we gathered, processed and/or transported approximately 7.3
billion cubic feet per day of raw natural gas. During 1999, our natural gas
gathering, processing, transportation, marketing and storage activities produced
$981.5 million of gross margin and $592.4 million of EBITDA, excluding general
and administrative expenses.

Our raw natural gas gathering and processing operations are located in 11
contiguous states in the United States and two provinces in Western Canada. We
provide services in the following key North American natural gas and oil
producing regions; Permian Basin, Mid-Continent, East Texas-Austin Chalk-North
Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and
Western Canada. We have a significant presence in the first five of these
producing regions where, according to the Oil and Gas Journal's "1999 Worldwide
Gas Processing Report," we are among the three largest midstream natural gas
companies based on volumes of natural gas gathered and processed or volumes of
NGLs produced.

Raw Natural Gas Supply Arrangements. Typically, we take ownership of raw
natural gas at the wellhead. Each producer generally dedicates to us the raw
natural gas produced from designated oil and natural gas leases for a specific
term. The term will typically extend for three to seven years. We currently have
more than 15,000 active contracts with over 5,000 producers. We obtain access to
raw natural gas and provide our midstream natural gas service principally under
three types of contracts: percentage-of-proceeds contracts, fee-based contracts
and keep-whole contracts. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Overview -- Effects of Our Raw Natural
Gas Supply Arrangements" for a description of these types of contracts.

Raw Natural Gas Gathering. As of December 31, 1999, we had approximately 17
trillion cubic feet of raw natural gas supplies attached to our systems. We
receive raw natural gas from a diverse group of producers under contracts with
varying durations to provide a stable supply of raw natural gas through our
processing plants. A significant portion of the raw natural gas that is
processed by us is produced by large producers, including ExxonMobil, Union
Pacific Resources, BP Amoco and Phillips, which together account for
approximately 20% of our processed raw natural gas.

We continually seek new supplies of raw natural gas, both to offset natural
declines in production from connected wells and to increase throughput volume.
Historically, we have been successful in connecting additional supplies to more
than offset natural declines in production.

We obtain new well connections in our operating areas by contracting for
production from new wells or by obtaining raw natural gas that has been released
from other gathering systems. Producers may switch raw natural gas from one
gathering system to another to obtain better commercial terms, conditions and
service levels.

We believe our significant asset base and scope of our operations provides
us with significant opportunities to add released raw natural gas to our
systems. In addition, we have significant processing capacity in the Onshore
Gulf of Mexico, Offshore Gulf of Mexico and Rocky Mountain regions, which,

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according to the EIA Report contain significant quantities of proved natural gas
reserves. We also have a presence in other potential high-growth areas such as
the Western Canadian Sedimentary Basin. As a result of new connections resulting
from both increased drilling and released raw natural gas, we connected
approximately 1,300 additional wells in 1998 and 1,500 additional wells in 1999.

Gathering systems are operated at design pressures that will maximize the
total throughput from all connected wells. On gathering systems where it is
economically feasible, we operate at a relatively low pressure, which can allow
us to offer a significant benefit to raw natural gas producers. Specifically,
lower pressure gathering systems allow wells, which produce at progressively
lower field pressures as they age, to remain connected to gathering systems and
continue to produce for longer periods of time. As the pressure of a well
declines, it becomes increasingly more difficult to deliver the remaining
production in the ground against a higher pressure that exists in the connecting
gathering system. Field compression is typically used to lower the pressure of a
gathering system. If field compression is not installed, then the remaining
production in the ground will not be produced because it cannot overcome the
higher gathering system pressure. In contrast, if field compression is
installed, then a well can continue delivering production that otherwise would
not be produced. Our field compression systems provide the flexibility of
connecting a high pressure well to the downstream side of the compressor even
though the well is producing at a pressure greater than the upstream side. As
the well ages and the pressure naturally declines, the well can be reconnected
to the upstream, low pressure side of the compressor and continue to produce. By
maintaining low pressure systems with field compression units, we believe that
the wells connected to our systems are able to produce longer and at higher
volumes before disconnection is required.

Raw Natural Gas Processing. Most of our natural gas gathering systems feed
into our natural gas processing plants. Our processing plants produced an
average of approximately 4.7 billion cubic feet per day of residue gas and an
average of approximately 400,000 barrels per day of NGLs during 1999.

Our natural gas processing operations involve the extraction of NGLs from
raw natural gas, and, at certain facilities, the fractionation of NGLs into
their individual components (ethane, propane, butanes and natural gasoline). We
sell NGLs produced by our processing operations to a variety of customers
ranging from large, multi-national petrochemical and refining companies,
including Phillips, to small, regional retail propane distributors.

At three plants, we also extract helium from the residue gas stream. Helium
is used for medical diagnostics, in arc welding and other metallurgical and
chemical processes, in the space exploration program and other scientific
applications, for diluting oxygen for breathing (by patients with respiratory
ailments and by deep-sea divers) and for inflating lighter-than-air aircraft and
balloons. These plants are among the few helium extraction facilities in the
United States. We extracted approximately 1.3 billion cubic feet of helium
during 1999, producing revenues of approximately $33 million.

Hydrogen sulfide also is separated in the treating and processing cycle.
During 1999, we produced and sold approximately 93,000 long tons of sulfur,
producing revenues of approximately $1.1 million.

We also remove off-quality crude oil, nitrogen, carbon dioxide and brine
from the raw natural gas stream. The nitrogen and carbon dioxide are released
into the atmosphere, and the crude oil and brine are accumulated and stored
temporarily at field compressors or the various plants. The brine is transported
to licensed disposal wells owned either by us or by third parties. The crude oil
is sold in the off-quality crude oil market.

Residue Gas Marketing. In addition to our gathering and processing
activities discussed above, we are involved in the purchase and sale of residue
gas, directly or through our wholly owned gas marketing company. Our gas
marketing efforts primarily involve supplying the residue gas demands of
end-user customers that are physically attached to our pipeline systems and
supplying the gas processing requirements associated with our keep-whole
processing agreements.

We are focused on extracting the highest possible value for the residue gas
that results from our processing and transportation operations. Of the residue
gas that we market, we currently sell approximately 25% to various on-system
users and approximately 75% to industrial end-users, national
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wholesale gas marketing companies (including Duke Energy Trading and Marketing,
a subsidiary of Duke Energy and one of the largest gas marketers in the United
States) and electric utilities.

Our Spindletop storage facility plays an important role in our ability to
act as a full-service natural gas marketer. We lease approximately two-thirds of
the facility's capacity to our customers, and we use the balance to manage
relatively constant natural gas supply volumes with uneven demand levels and
provide "backup" service to our customers.

The natural gas marketing industry is a highly competitive commodity
business with a significant degree of price transparency. We provide a full
range of natural gas marketing services in conjunction with the gathering,
processing, and transportation services we offer on our facilities, which allows
us to use our asset infrastructure to enhance our revenues across each aspect of
the natural gas value chain.

Financial Services. We provide mezzanine financing to producers seeking
capital for production enhancement in our core physical and marketing asset
areas. We provide financing to operators as part of our efforts to increase
utilization of our existing assets, gain access to incremental supplies and
generate opportunities for us to expand existing infrastructure and/or construct
new gathering lines and processing facilities. The majority of the financing
plans we offer are asset-based. This program has created significant gathering
and processing opportunities for us. At December 31, 1999, we had $21.9 million
in financing outstanding under this program.

REGIONS OF OPERATIONS

Our operations cover substantially all of the major natural gas producing
regions in the United States, as well as portions of Western Canada. In
addition, our geographic diversity reduces the impact of regional price
fluctuations and regional changes in drilling activity.

Our raw natural gas gathering and processing assets are managed in line
with the seven geographic regions in which we operate. The following table
provides information concerning the raw natural gas gathering systems and
processing plants owned or operated by us at March 31, 2000.
<TABLE>
<CAPTION>

COMPANY PLANTS
GAS GATHERING OPERATED OPERATED NET PLANT
REGION SYSTEM(MILES) PLANTS BY OTHERS CAPACITY(MMCF/D)
------ ------------- -------- --------- ----------------
<S> <C> <C> <C> <C>
Permian Basin........ 12,890 19 2 1,417
Mid-Continent........ 30,820 19 2 2,273
East Texas-Austin
Chalk-North
Louisiana.......... 5,869 10 1 1,555
Onshore Gulf of
Mexico............. 3,008 7 1 1,083
Rocky Mountains...... 3,765 10 1 600
Offshore Gulf of
Mexico............. 490 2 6 909
Western Canada....... 144 3 0 109
------ -- -- -----
Total................ 56,986 70 13 7,946
====== == == =====

<CAPTION>
1999 OPERATING DATA
--------------------------------------------------------
PLANT INLET RESIDUE GAS NGLS
REGION VOLUME(MMCF/D) PRODUCTION(MMCF/D) PRODUCTION(BBLS/D)
------ -------------- ------------------ ------------------
<S> <C> <C> <C>
Permian Basin........ 1,123 816 124,507
Mid-Continent........ 1,459 1,223 120,551
East Texas-Austin
Chalk-North
Louisiana.......... 1,033 937 69,420
Onshore Gulf of
Mexico............. 757 675 37,944
Rocky Mountains...... 387 319 24,708
Offshore Gulf of
Mexico............. 736 691 15,148
Western Canada....... 76 72 278
----- ----- -------
Total................ 5,571 4,733 392,556(1)
===== ===== =======
</TABLE>

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

(1) Excludes approximately 7,500 barrels per day processed at third party plants
on our behalf.

Our key suppliers of raw natural gas in these seven regions include major
integrated oil companies, independent oil and gas producers, intrastate pipeline
companies and natural gas marketing companies. Our principal competitors in this
segment of our business consist of major integrated oil companies, independent
oil and gas gathers, and interstate and intrastate pipeline companies.

Regional Growth Strategies. Growth of our gas gathering and processing
operations is key to our success. Increased raw natural gas supply enables us to
increase throughput volumes and asset utilization throughout our entire
midstream natural gas value chain. As we develop our regional growth strategies,
we evaluate the nature of the opportunity that a particular region presents. The
attributes that we evaluate include the nature of the gas reserves and
production profile, existing midstream infrastructure including

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capacity and capabilities, the regulatory environment, the characteristics of
the competition, and the competitive position of our assets and capabilities. In
a general sense, we employ one or more of the strategies described below:

- Growth -- in regions where production is expected to grow significantly
and/or there is a need for additional gathering and processing
infrastructure, we plan to expand our gathering and processing assets by
following a disciplined acquisition strategy, by expanding existing
infrastructure, and by constructing new gathering lines and processing
facilities.

- Consolidation -- in regions that include mature producing basins with
flat to declining production or that have excess gathering and processing
capacity, we seek opportunities to efficiently consolidate the existing
asset base in order to increase utilization and operating efficiencies
and realize economies of scale.

- Opportunistic -- in regions where production growth is not primarily
generated by new exploration drilling activity we intend to optimize our
existing assets and selectively expand certain facilities or construct
new facilities to seize opportunities to increase our throughput. These
regions are generally experiencing stable to increasing production
through the application of new drilling technologies like 3-D seismic,
horizontal drilling and improved well completion techniques. The
application of new technologies is causing the drilling of additional
wells in areas of existing production and recompletions of existing wells
which create additional opportunities to add new gas supplies.

In each region, we plan to apply both our broad overall business strategy
and the strategy uniquely suited to each region. We believe this plan will yield
balanced growth initiatives, including new construction in certain high growth
areas, expansion of existing systems and complementary acquisitions, combined
with efficiency improvements and/or asset consolidation. We also plan to
rationalize assets and redeploy capital to higher value opportunities.

A description of our operations, key suppliers and principal competitors in
each region is set forth below:

Permian Basin. Our facilities in this region are located in West Texas and
Southeast New Mexico. We own majority interests in and are the operator of 19
natural gas processing plants in this region. In addition, we own minority
interests in two other natural gas processing plants that are operated by
others. Our natural gas processing plants are strategically located to access
production of the Permian Basin. Our plants have processing capacity net to our
interest of 1.4 billion cubic feet of raw natural gas per day. Operations in
this region are primarily focused on gathering and processing, but we also are
positioned for marketing residue gas and NGLs. We offer low, intermediate, and
high pressure gathering and processing and both high and low NGLs content
treating. Three of our processing facilities provide fractionation services.
Residue gas sales are enhanced by access to the Waha Hub where multiple pipeline
interconnects source gas for virtually every market in the United States. Our
older facilities have been modernized to improve product recoveries, and most of
our plants offer sulfur removal. During 1999, these plants operated at an
overall 79% capacity utilization rate. On average, the raw natural gas from West
Texas contains approximately 5.2 gallons of NGLs per thousand cubic feet, while
raw natural gas from New Mexico contains approximately 4.6 gallons of NGLs per
thousand cubic feet.

As we generally pursue a consolidation strategy in this region, our assets
will allow us to compete for new gas supplies in most major fields and benefit
from the expected increase in drilling and production from technological
advances. In addition, our ability to redirect gas between several processing
plants allows us to maximize utilization of our processing capacity in this
region.

Our key suppliers in this region include ExxonMobil, Union Pacific
Resources and Yates Petroleum. Our principal competitors in this region include
Dynegy, Koch and Texaco.

Mid-Continent. Our facilities in this region are located in Oklahoma,
Kansas and the Texas Panhandle. In this region, we own and are the operator of
19 natural gas processing plants, 18 in which we
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own a 100% interest and one in which we own a 50% interest. We also own minority
interests in two other natural gas processing plants that are operated by
others. We gather and process raw natural gas primarily from the Arkoma,
Ardmore, and Anadarko basins, including the prolific Hugoton and Panhandle
fields. Our plants have processing capacity net to our interest of 2.3 billion
cubic feet of raw natural gas per day. During 1999, our plants operated at an
overall 65% capacity utilization rate. On average, the raw natural gas from this
region contains from 3 to 5 gallons of NGLs per thousand cubic feet.

We also produce approximately 28% of the United States domestic supply of
helium from our Mid-Continent facilities. Annual growth in demand for helium
over the past 15 years has been approximately 8.5% per year. Because of its
unique characteristics and use as an industrial gas, we expect demand for helium
to grow well into the future.

Existing production in the Mid-Continent region is typically from mature
fields with shallow decline profiles that will provide our plants with a
dependable source of raw natural gas over a long term. With the development of
improved exploration and production techniques such as 3-D seismic and
horizontal drilling over the past several years, additional reserves have become
economically producible in this region. We hold large acreage dedication
positions with various producers who have developed programs to add
substantially to their reserve base. The infrastructure of our plants and
gathering facilities are uniquely positioned to pursue our consolidation
strategy.

Our key suppliers in this region include Phillips, OXY USA and Anadarko
Petroleum. Our principal competitors in this region include Coastal Field
Services, Oneok Field Services and Enogex Inc.

East Texas-Austin Chalk-North Louisiana. Our facilities in this region are
located in East Texas, North Louisiana and the Austin Chalk formation of East
Central Texas and Central Louisiana. We own majority interests in and are the
operator of 10 natural gas processing plants in this region. In addition, we own
a minority interest in one natural gas processing plant that is operated by
another entity. Our plants have processing capacity net to our interest of 1.6
billion cubic feet of raw natural gas per day. During 1999, these plants
operated at an overall 66% capacity utilization rate. In this region we also own
three intrastate gathering systems, which, in the aggregate, can gather and
transport approximately 480 million cubic feet of raw natural gas per day.

Our East Texas operations are centered around our East Texas Complex,
located near Carthage, Texas. This plant complex is the second largest raw
natural gas processing facility in the continental United States, based on
liquids recovery, and currently produces approximately 40,000 barrels per day of
NGLs. Our 165-mile gathering network aggregates production to the East Texas
Complex, which currently gathers approximately 130 million cubic feet of raw
natural gas per day. In addition, the plant is connected to and processes raw
natural gas from several other gathering systems, including those owned by Koch,
Union Pacific Resources and American Central. Substantially all of the raw
natural gas processed at the complex is contracted under percent-of-proceeds
agreements with an average remaining term of approximately six years. This plant
is adjacent to our Carthage Hub, which delivers residue gas to interconnects
with 14 interstate and intrastate pipelines. The Carthage Hub, with an aggregate
delivery capacity of two billion cubic feet per day, acts as a key exchange
point for the purchase and sale of residue gas. We also operate Panola pipeline,
with throughput capacity of up to 40,000 barrels per day, which carries NGLs
from our East Texas Complex to markets in Mont Belvieu, Texas. In this region,
we also own and operate the Fuels Cotton Valley Gathering System, which consists
of 76 miles of pipeline and which gathers approximately 30 million cubic feet of
raw natural gas per day.

As we pursue a combination of opportunistic and consolidation strategies in
this diverse region, we intend to leverage our modern processing capacity,
intrastate gas pipeline and NGL assets.

Our key suppliers in this region include Union Pacific Resources, Devon and
Phillips. Our principal competitors in this region include Koch, El Paso Field
Services and Southwest Pipeline Corporation.

Onshore Gulf of Mexico. Our facilities in this region are located in South
Texas and the Southeastern portions of the Texas Gulf Coast. We own a 100%
interest in and are the operator of seven natural gas processing plants and the
Spindletop gas storage facility in this region. In addition, we own a
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minority interest in one natural gas processing plant that is operated by
another entity. Our plants have processing capacity net to our interest of 1.1
billion cubic feet of raw natural gas per day. During 1999, the plants in this
region ran at an overall 70% capacity utilization rate.

Our Spindletop natural gas storage facility is located near Beaumont, Texas
and has current working natural gas capacity of 8.5 billion cubic feet, plus
expansion potential of up to an additional 10 billion cubic feet. We currently
have approximately 5.6 billion cubic feet of the available storage capacity
under lease with expiration terms out to July 2004. This high deliverability
storage facility is positioned to meet the needs of the natural gas-fired
electric generation marketplace, currently the fastest growing demand segment of
the natural gas industry. The facility interconnects with 12 interstate and
intrastate pipelines and is designed to handle the hourly demand needs of power
generators.

To achieve growth in our Onshore Gulf of Mexico region, we intend to fully
integrate our recently acquired assets and use the diversity of our current
asset base to provide value-added services to our broad customer base. We will
also seek additional opportunities to participate in the anticipated growth in
supply from this region.

Our key suppliers in this region include Collins & Ware, United Oil and
Minerals and TransTexas. Our principal competitors in this region include PG&E
Texas Transmission, Tejas Gas Corp. and Houston Pipe Line Company.

Rocky Mountains. Our facilities in this region are located in the DJ Basin
of Northern Colorado, the Ladder Creek area of Southeast Colorado and the
Greater Green River Basin and Overthrust Belt areas of Southwest Wyoming and
Northeast Utah. We own a 100% interest in and are the operator of 10 natural gas
processing plants in this region. In addition, we own a minority interest in one
natural gas processing plant that is operated by another entity. Our plants have
processing capacity net to our interest of 600 million cubic feet of raw natural
gas per day. During 1999, our plants in this region operated at an overall 65%
capacity utilization rate. These assets provide for the gathering and processing
of raw natural gas, the transportation and fractionation of NGLs, nitrogen
rejection, and helium extraction and liquification services.

The Rocky Mountains region has well placed assets with strong competitive
positions in areas that are expected to benefit from increased drilling
activity, providing us with a platform for growth. In this region, we expect to
achieve growth through our existing assets, strategic acquisitions and
development of new facilities. In addition, we intend to pursue an opportunistic
strategy in areas where new technologies and recovery methods are being
employed.

Our key suppliers in the region include Patina Oil & Gas, HS Resources and
Union Pacific Resources. Our principal competitors in this region include HS
Resources, Williams Field Services and Western Gas Resources.

Offshore Gulf of Mexico. Our facilities in this region are located along
the Gulf Coast areas of Louisiana, Mississippi and Alabama. We own minority
interests in and are the operator of two natural gas processing plants in this
region. In addition, we own a 50% interest in one natural gas processing plant
and minority interests in five other natural gas processing plants, all of which
are operated by other entities. The plants have processing capacity net to our
interest of 909 million cubic feet of raw natural gas per day. During 1999, our
plants in this region operated at an overall 81% capacity utilization rate. Each
of these plants straddle offshore pipeline systems delivering a relatively lower
NGLs content gas stream than that of our onshore gathering systems, as
approximately 50% of the produced NGLs content consists of ethane. As a result,
the offshore region's revenues are concentrated in fee-based business
arrangements and are less dependent on fluctuating commodity prices.

In addition, we own a 37% interest in the Dauphin Island Gathering
Partnership, an offshore gathering and transmission system. Dauphin Island has
attractive market outlets, including deliveries to Texas Eastern Transmission
Corporation, Transco, Koch, Gateway and Florida Gas Transmission for re-delivery
to the Southeast, Mid-Atlantic, Northeast and New England natural gas markets.
Dauphin Island's leased capacity on Texas Eastern Transmission Corporation's
pipeline provides us with a means to
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cross the Mississippi River to deliver or receive production from the Venice,
Louisiana natural gas hub area. Further, the Main Pass Oil Gathering Company
system, in which we own a 33% interest, also has access to a variety of markets
through existing shallow-water and deep-water interconnections and dual market
outlets into Shell's Delta terminal as well as Chevron's Cypress terminal.

We believe that the Offshore Gulf of Mexico production area will be one of
the most active regions for new drilling in the United States. Our strategic
growth plan for this region is to add new facilities to our existing base so
that we can capture new offshore development opportunities. Our existing assets
in the eastern Gulf of Mexico are positioned to access new and ongoing
production developments. Based on our broad range of assets in the region, we
intend to capture incremental margins along the natural gas value chain.

Our key suppliers in the Offshore Gulf of Mexico region include Coastal,
ExxonMobil and CNG Producing Company. Our principal competitors in this region
include El Paso Energy, Coral Energy and Williams.

Western Canada. We own a majority interest in and are the operator of three
natural gas processing plants in Western Canada that are strategically located
in the Peace River Arch area of Northwestern Alberta. Our facilities in this
region have processing capacity net to our interest of 109 million cubic feet of
raw natural gas per day. Our 144-mile gathering system located in this region
supports these processing facilities. During 1999, our processing plants in this
area operated at an overall 70% capacity utilization rate. Our processing
facilities in this area are new, with the majority having been constructed since
1995. Our processing arrangements are primarily fee-based, providing an income
stream that is not subject to fluctuations in commodity prices.

The Peace River Arch area continues to be an active drilling area with land
widely held among several large and small producers. Multiple residue gas market
outlets can be accessed from our facilities through connections to TransCanada's
NOVA system, the Westcoast system into British Columbia and the Alliance
Pipeline, scheduled to be operational in October 2000.

According to the EIA Report, less than 20% of the gathering and processing
assets in the area are owned by midstream gathering and processing companies. As
a result, we believe that significant growth opportunities exist in this region.
We anticipate that producers in this area may follow the lead of U.S. producers
and divest their midstream assets over the next few years. We are positioned to
capitalize on this fundamental shift in the Canadian natural gas processing
industry and plan to expand our position in Alberta and British Columbia through
additional acquisitions and greenfield projects.

Our key suppliers in this region include Star Oil & Gas Ltd., Talisman
Energy Inc. and Anderson Exploration Ltd. Our principal competitors in the area
include TransCanada Midstream, Talisman Energy Inc. and Westcoast Energy, Inc.

NATURAL GAS LIQUIDS TRANSPORTATION, FRACTIONATION AND MARKETING

OVERVIEW

We market our NGLs and provide marketing services to third party NGL
producers and sales customers in significant NGL production and market centers
in the United States. During 1999, our NGL transportation, fractionation and
marketing activities produced $38.3 million of gross margin and $38.1 million of
EBITDA, excluding general and administrative expenses. In 1999, we marketed and
traded approximately 486,000 barrels of NGLs per day, of which approximately 85%
was production for our own account, ranking us as one of the largest NGLs
marketers in the country.

Our NGL services include plant tailgate purchases, transportation,
fractionation, flexible pricing options, price risk management and
product-in-kind agreements. Our primary NGL operations are located in close
proximity to our gathering and processing assets in each of the regions in which
we operate, other than Western Canada. We own interests in two NGLs
fractionators at the Mont Belvieu, Texas market center, the Mont Belvieu I
fractionation facility and the Enterprise Products fractionation facility. In

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addition, we own interests in two major NGLs pipelines serving the Mont Belvieu
facilities, the wholly owned Panola Pipeline in East Texas and an interest in
the Black Lake Pipeline in Louisiana and East Texas. We also own several
regional fractionation plants and NGLs pipelines.

We possess a large asset base of NGL fractionators and pipelines that are
used to provide value-added services to our refining, chemical, industrial,
retail and wholesale propane-marketing customers. We intend to capture premium
value in local markets while maintaining a low cost structure by maximizing
facility utilization at our 12 regional fractionators and 12 pipeline systems.
Our current fractionation capacity is approximately 152,000 barrels per day.

STRATEGY

Our strategy is to exploit the size, scope and reliability of supply from
our raw natural gas processing operations and apply our knowledge of NGL market
dynamics to make additional investments in NGL infrastructure. Our
interconnected natural gas processing operations provide us with an opportunity
to capture fee-based investment opportunities in certain NGL assets, including
pipelines, fractionators and terminals. In conjunction with this investment
strategy and as an enhancement to the margin generation from our NGL assets, we
also intend to focus on the following areas: producer services, local sales and
fractionation, market hub fractionation, transportation and market center
trading and storage, each of which briefly is discussed below.

Producer Services. We plan to expand our services to producers principally
in the areas of price risk management and handling the marketing of their
products. Over the last several years, we have expanded our supply base
significantly beyond our own equity production by providing a long-term market
for third-party NGLs at competitive prices.

Local Sales and Fractionation. We will seek opportunities to maximize value
of our product by expanding local sales. We have fractionation capabilities at
14 of our raw natural gas processing plants. Our ability to fractionate NGLs at
regional processing plants provides us with direct access to local NGLs markets.

Market Hub Fractionation. We will focus on optimizing our product slate
from our two Gulf Coast fractionators, the Mont Belvieu I and Enterprise
Products fractionators, where we have a combined owned capacity of 57,000
barrels per day. The control of products from these fractionators complements
our market center trading activity.

Transportation. We will seek additional opportunities to invest in NGL
pipelines and secure favorable third party transportation arrangements. We use
company-owned NGL pipelines to transport approximately 94,500 barrels per day of
our total NGL pipeline volumes, providing transportation to market center
fractionation hubs or to end use markets. We also are a significant shipper on
third party pipelines in the Rocky Mountains, Mid-Continent and Permian Basin
producing regions and, as a result, receive the benefit of incentive rates on
many of our NGLs shipments.

Market Center Trading and Storage. We use trading and storage at the Mont
Belvieu, Texas and Conway, Kansas NGL market centers to manage our price risk
and provide additional services to our customers. We undertake these activities
through the use of fixed forward sales, basis and spread trades, storage
opportunities, put/call options, term contracts and spot market trading. We
believe there are additional opportunities to grow our price risk management
services with our industrial customer base.

KEY SUPPLIERS AND COMPETITION

The marketing of NGLs is a highly competitive business that involves
integrated oil and natural gas companies, mid-stream gathering and processing
companies, trading houses, international liquid propane gas producers and
refining and chemical companies. There is competition to source NGLs from plant
operators for movement through pipeline networks and fractionation facilities as
well as to supply large consumers such as multi-state propane, refining and
chemical companies with their NGLs needs. Our three largest suppliers are our
own plants, Union Pacific Resources and Pacific Gas & Electric. Our largest
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sales customers are Phillips, Dow Chemical and ExxonMobil, which accounted for
12%, 2% and 1%, respectively, of our total revenues in 1999. Our three principal
competitors in the marketing of NGLs are Dynegy, Koch and Enterprise. In 1999,
we marketed and traded an average of approximately 486,000 barrels per day, or
approximately 19% of the available domestic supply, which includes gas plant
production, refinery plant production and imports.

TEPPCO

On March 31, 2000, we obtained by transfer from Duke Energy, the general
partner of TEPPCO, a publicly traded limited partnership. TEPPCO operates in two
principal areas:

- refined products and liquefied petroleum gases transportation; and

- crude oil and NGLs transportation and marketing.

TEPPCO is one of the largest pipeline common carriers of refined petroleum
products and liquefied petroleum gases in the United States. Its operations in
this line of business consist of:

- interstate transportation, storage and terminaling of petroleum products;

- short-haul shuttle transportation of liquefied petroleum gas at the Mont
Belvieu, Texas complex;

- sale of product inventory;

- fractionation of NGLs; and

- ancillary services.

TEPPCO's refined products and liquefied petroleum gas pipeline system includes
approximately 4,300 miles of pipeline which extend from southeast Texas through
the central and midwestern United States to the northeastern United States.
TEPPCO's refined products and liquefied petroleum gas pipeline system has
storage capacity of 13 million barrels of refined petroleum products and 38
million barrels of liquefied petroleum gas.

Through its crude oil and NGLs transportation and marketing business,
TEPPCO gathers, stores, transports and markets crude oil, NGLs, lube oil and
specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain
region. TEPPCO's crude oil and NGLs assets include approximately 1,950 miles of
crude oil pipeline and 1.7 million barrels of crude oil storage and
approximately 425 miles of NGL pipeline with an aggregate capacity of 25,000
barrels per day.

We believe that our ownership of the general partnership interest of TEPPCO
improves our business position in the transportation sector of the midstream
natural gas industry and provides us additional flexibility in pursuing our
disciplined acquisition strategy by providing an alternative acquisition
vehicle. It also provides us with an opportunity to sell appropriate assets
currently held by our company to TEPPCO.

The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO
partnership agreement and the partnership agreements of its operating
partnerships. Under the partnership agreements, the general partner of TEPPCO is
reimbursed for all direct and indirect expenses it incurs or payments it makes
on behalf of TEPPCO.

TEPPCO makes quarterly cash distributions of its available cash, which
consists generally of all cash receipts less disbursements and cash reserves
necessary for working capital, anticipated capital expenditures and
contingencies, the amounts of which are determined by the general partner of
TEPPCO.

The partnership agreements provide for incentive distributions payable to
the general partner of TEPPCO out of TEPPCO's available cash in the event
quarterly distributions to its unitholders exceed certain specified targets. In
general, subject to certain limitations, if a quarterly distribution exceeds a

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target of $.275 per limited partner unit, the general partner of TEPPCO will
receive incentive distributions equal to:

- 15% of that portion of the distribution per limited partner unit which
exceeds the minimum quarterly distribution amount of $.275 but is not
more than $.325, plus

- 25% of that portion of the quarterly distribution per limited partner
unit which exceeds $.325 but is not more than $.45, plus

- 50% of that portion of the quarterly distribution per limited partner
unit which exceeds $.45.

At TEPPCO's 1999 per unit distribution level, the general partner:

- receives approximately 14% of the cash distributed by TEPPCO to its
partners, which consists of 12% from the incentive cash distribution and
2% from the general partner interest; and

- under the incentive cash distribution provisions, receives 50% of any
increase in TEPPCO's per unit cash distributions.

During 1999, total cash distributions to the general partner of TEPPCO were
$8.3 million.

NATURAL GAS SUPPLIERS

We purchase substantially all of our raw natural gas from producers under
varying term contracts. Typically, we take ownership of raw natural gas at the
wellhead, settling payments with producers on terms set forth in the applicable
contracts. These producers range in size from small independent owners and
operators to large integrated oil companies, such as Phillips, our largest
single supplier. No single producer accounted for more than 10% of our natural
gas throughput in 1999. Each producer generally dedicates to us the raw natural
gas produced from designated oil and natural gas leases for a specific term. The
term will typically extend for three to seven years and in some cases for the
life of the lease. We currently have over 15,000 active contracts with over
5,000 producers. We consider our relations with our producers to be good. For a
description of the types of contracts we have entered into with our suppliers,
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Overview -- Effects of Our Raw Natural Gas Supply Arrangements."

COMPETITION

We face strong competition in acquiring raw natural gas supplies. Our
competitors in obtaining additional gas supplies and in gathering and processing
raw natural gas include:

- major integrated oil companies;

- major interstate and intrastate pipelines or their affiliates;

- other large raw natural gas gatherers that gather, process and market
natural gas and/or NGLs; and

- a relatively large number of smaller raw natural gas gatherers of varying
financial resources and experience.

Competition for raw natural gas supplies is concentrated in geographic
regions based upon the location of gathering systems and natural gas processing
plants. Although we are one of the largest gatherers and processors in most of
the geographic regions in which we operate, most producers in these areas have
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alternate gathering and processing facilities available to them. In addition,
producers have other alternatives, such as building their own gathering
facilities or in some cases selling their raw natural gas supplies without
processing. Competition for raw natural gas supplies in these regions is
primarily based on:

- the reputation, efficiency and reliability of the gatherer/processor,
including the operating pressure of the gathering system;

- the availability of gathering and transportation;

- the pricing arrangement offered by the gatherer/processor; and

- the ability of the gatherer/processor to obtain a satisfactory price for
the producers' residue gas and extracted NGLs.

In addition to competition in raw natural gas gathering and processing,
there is vigorous competition in the marketing of residue gas. Competition for
customers is based primarily upon the price of the delivered gas, the services
offered by the seller, and the reliability of the seller in making deliveries.
Residue gas also competes on a price basis with alternative fuels such as oil
and coal, especially for customers that have the capability of using these
alternative fuels and on the basis of local environmental considerations. Also,
to foster competition in the natural gas industry, certain regulatory actions of
FERC and some states have allowed buying and selling to occur at more points
along transmission and distribution systems.

Competition in the NGLs marketing area comes from other midstream NGLs
marketing companies, international producers/traders, chemical companies and
other asset owners. Along with numerous marketing competitors, we offer price
risk management and other services. We believe it is important that we tailor
our services to the end-use customer to remain competitive.

REGULATION

Transportation. Historically, the transportation and sale for resale of
natural gas in interstate commerce have been regulated under the Natural Gas Act
of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated
thereunder by FERC. In the past, the federal government regulated the prices at
which natural gas could be sold. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy
Act price and non-price controls affecting wellhead sales of natural gas.
Congress could, however, reenact field natural gas price controls in the future,
though we know of no current initiative to do so.

As a gatherer, processor and marketer of raw natural gas, we depend on the
natural gas transportation and storage services offered by various interstate
and intrastate pipeline companies to enable the delivery and sale of our residue
gas supplies. In accordance with methods required by FERC for allocating the
system capacity of "open access" interstate pipelines, at times other system
users can preempt the availability of interstate natural gas transportation and
storage service necessary to enable us to make deliveries and sales of residue
gas. Moreover, shippers and pipelines may negotiate the rates charged by
pipelines for such services within certain allowed parameters. These rates will
also periodically vary depending upon individual system usage and other factors.
An inability to obtain transportation and storage services at competitive rates
can hinder our processing and marketing operations and affect our sales margins.

The intrastate pipelines that we own are subject to state regulation and,
to the extent they provide interstate services under Section 311 of the Natural
Gas Policy Act of 1978, also are subject to FERC regulation. We also own an
interest in a natural gas gathering system and interstate transmission system
located in offshore waters south of Louisiana and Alabama. The offshore
gathering system is not a jurisdictional entity under the Natural Gas Act; the
interstate offshore transmission system is regulated by FERC.

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Commencing in April 1992, FERC issued Order No. 636 and a series of related
orders that require interstate pipelines to provide open-access transportation
on a basis that is equal for all marketers of natural gas. FERC has stated that
it intends for Order No. 636 to foster increased competition within all phases
of the natural gas industry. Order No. 636 applies to our activities in Dauphin
Island Gathering Partners and how we conduct gathering, processing and marketing
activities in the market place serviced by Dauphin Island Gathering Partners.
The courts have largely affirmed the significant features of Order No. 636 and
the numerous related orders pertaining to individual pipelines, although certain
appeals remain pending and FERC continues to review and modify its regulations.
For example, the FERC recently issued Order No. 637 which, among other things:

- lifts the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002 for short-term releases of
pipeline capacity of less than one year;

- permits pipelines to charge different maximum cost-based rates for peak
and off-peak periods;

- encourages, but does not mandate, auctions for pipeline capacity;

- requires pipelines to implement imbalance management services;

- restricts the ability of pipelines to impose penalties for imbalances,
overruns and non-compliance with operational flow orders; and

- implements a number of new pipeline reporting requirements.

Order No. 637 also requires the FERC to analyze whether the FERC should
implement additional fundamental policy changes, including, among other things,
whether to pursue performance-based ratemaking or other non-cost based
ratemaking techniques and whether the FERC should mandate greater
standardization in terms and conditions of service across the interstate
pipeline grid. In addition, the FERC recently implemented new regulations
governing the procedure for obtaining authorization to construct new pipeline
facilities and has issued a policy statement, which it largely affirmed in a
recent order on rehearing, establishing a presumption in favor of requiring
owners of new pipeline facilities to charge rates based solely on the costs
associated with such new pipeline facilities. We cannot predict what further
action FERC will take on these matters. However, we do not believe that we will
be affected by any action taken previously or in the future on these matters
materially differently than other natural gas gatherers, processors and
marketers with which we compete.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, FERC and the courts. The natural gas
industry historically has been heavily regulated; therefore, there is no
assurance that the less stringent and pro-competition regulatory approach
recently pursued by FERC and Congress will continue.

Gathering. The Natural Gas Act exempts natural gas gathering facilities
from the jurisdiction of FERC. Interstate natural gas transmission facilities,
on the other hand, remain subject to FERC jurisdiction. FERC has historically
distinguished between these two types of facilities on a fact-specific basis. We
believe that our gathering facilities and operations meet the current tests that
FERC uses to grant non-jurisdictional gathering facility status. However, there
is no assurance that FERC will not modify such tests or that all of our
facilities will remain classified as natural gas gathering facilities.

Some states in which we own gathering facilities have adopted laws and
regulations that require gatherers either to purchase without undue
discrimination as to source or supplier or to take ratably without undue
discrimination natural gas production that may be tendered to the gatherer for
handling. For example, the states of Oklahoma and Kansas also have adopted
complaint-based statutes that allow the Oklahoma Corporation Commission and the
Kansas Corporation Commission, respectively, to remedy discriminatory rates for
providing gathering service where the parties are unable to agree. In a similar
way, the Railroad Commission of Texas sponsors a complaint procedure for
resolving grievances about natural gas gathering access and rate discrimination.

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The FERC recently issued Order No. 639, requiring that virtually all
non-proprietary pipeline transporters of natural gas on the outer-continental
shelf report information on their affiliations, rates and conditions of service.
Among FERC's purposes in issuing these rules was the desire to provide shippers
on the outer-continental shelf with greater assurance of open-access services on
pipelines located on the outer-continental shelf and non-discriminatory rates
and conditions of service on these pipelines. The FERC exempted Natural Gas
Act-regulated pipelines, like Dauphin Island Gathering Partners, from the new
reporting requirements, reasoning that the information that these pipelines were
already reporting was sufficient to monitor conformity with existing
non-discrimination mandates. However, pipelines not regulated under the Natural
Gas Act, like our gathering lines located on the outer-continental shelf, must
comply with the new rules. This could increase our cost of regulatory compliance
and place us at a disadvantage in comparison to companies that are not required
to satisfy the reporting requirements. Order No. 639 may be altered on rehearing
or on appeal, and it is not known at this time what effect these new rules, as
they may be altered, will have on our business. We currently believe that Order
No. 639 and the related reporting requirements will not have a material adverse
effect on our existing business activities.

Processing. The primary function of our natural gas processing plants is
the extraction of NGLs and the conditioning of natural gas for marketing. FERC
has traditionally maintained that a processing plant that primarily extracts
NGLs is not a facility for transportation or sale of natural gas for resale in
interstate commerce and therefore is not subject to its jurisdiction under the
Natural Gas Act. We believe that our natural gas processing plants are primarily
involved in removing NGLs and, therefore, are exempt from the jurisdiction of
FERC.

Transportation and Sales of Natural Gas Liquids. We have non-operating
interests in two pipelines that transport NGLs in interstate commerce. The
rates, terms and conditions of service on these pipelines are subject to
regulation by the FERC under the Interstate Commerce Act. The Interstate
Commerce Act requires, among other things, that petroleum products (including
NGLs) pipeline rates be just and reasonable and non-discriminatory. The FERC
allows petroleum pipeline rates to be set on at least three bases, including
historic cost, historic cost plus an index or market factors.

Sales of Natural Gas Liquids. Our sales of NGLs are not currently regulated
and are made at market prices. In a number of instances, however, the ability to
transport and sell such NGLs are dependent on liquids pipelines whose rates,
terms and conditions or service are subject to the Interstate Commerce Act.
Although certain regulations implemented by the FERC in recent years could
result in an increase in the cost of transporting NGLs on certain petroleum
products pipelines, we do not believe that these regulations affect us any
differently than other marketers of NGLs with whom we compete.

U.S. Department of Transportation. Some of our pipelines are subject to
regulation by the U.S. Department of Transportation with respect to their
design, installation, testing, construction, operation, replacement and
management. Comparable regulations exist in some states where we do business.
These regulations provide for safe pipeline operations and include potential
fines and penalties for violations.

Safety and Health. Certain federal statutes impose significant liability
upon the owner or operator of natural gas pipeline facilities for failure to
meet certain safety standards. The most significant of these is the Natural Gas
Pipeline Safety Act, which regulates safety requirements in the design,
construction, operation and maintenance of gas pipeline facilities. In addition,
we are subject to a number of federal and state laws and regulations, including
the federal Occupational Safety and Health Act and comparable state statutes,
whose purpose is to maintain the safety of workers, both generally and within
the pipeline industry. We have an internal program of inspection designed to
monitor and enforce compliance with pipeline and worker safety requirements. We
believe we are in substantial compliance with the requirements of these laws,
including general industry standards, recordkeeping requirements, and monitoring
of occupational exposure to hazardous substances.

Canadian Regulation. Our Canadian assets in the province of Alberta are
regulated by the Alberta Energy and Utilities Board. Our West Doe natural gas
gathering pipeline, which crosses the Alberta/ British Columbia border, falls
under the jurisdiction of the National Energy Board.
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ENVIRONMENTAL MATTERS

The operation of pipelines, plants and other facilities for gathering,
transporting, processing, treating, or storing natural gas, NGLs and other
products is subject to stringent and complex laws and regulations pertaining to
health, safety and the environment. As an owner or operator of these facilities,
we must comply with these laws and regulations at the federal, state, and local
levels. These laws and regulations can restrict or prohibit our business
activities that affect the environment in many ways, such as:

- restricting the way we can release materials or waste products into the
air, water, or soils;

- limiting or prohibiting construction activities in sensitive areas such
as wetlands or areas of endangered species habitat, or otherwise
constraining how or when construction is conducted;

- requiring remedial action to mitigate pollution from former operations,
or requiring plans and activities to prevent pollution from ongoing
operations; and

- imposing substantial liabilities on us for pollution resulting from our
operations, including, for example, potentially enjoining the operations
of facilities if it were determined that they were not in compliance with
permit terms.

In most instances, the environmental laws and regulations affecting our
operations relate to the potential release of substances or waste products into
the air, water or soils, and include measures to control or prevent the release
of substances or waste products to the environment. Costs of planning,
designing, constructing and operating pipelines, plants, and other facilities
must incorporate compliance with environmental laws and regulation and safety
standards. Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and potentially criminal enforcement measures,
which can include the assessment of monetary penalties, the imposition of
remedial requirements, the issuance of injunctions and federally authorized
citizen suits. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of substances or other waste products to the environment.
The following is a discussion of certain environmental and safety concerns that
relate to the midstream natural gas and NGLs industry. It is not intended to
constitute a complete discussion of all applicable federal, state and local laws
and regulations, or specific matters, to which we may be subject.

Our operations are regulated by the Clean Air Act, as amended, and
comparable state laws and regulations. These laws and regulations govern
emissions into the air from our activities, for example in relation to our
processing plants and our compressor stations, and also impose procedural
requirements on how we conduct our operations. Due to the nature or our
business, we have numerous permits related to air emissions issued by state
governments or the United States Environmental Protection Agency ("EPA"). For
example, we have a large number of federal Operating Permits, known as Title V
permits, for our facilities that can impart specific emissions limitations as
well as specific operational practices or administrative requirements with which
we must comply. There are also other state and federal requirements that might
relate to our operations, including the federal Prevention of Significant
Deterioration permitting requirements for major sources of emissions, and
specific New Source Performance Standards or Maximum Achievable Control
Technology ("MACT") Standards issued by the EPA that apply specifically to our
industry or activities. Our failure to comply with these requirements exposes us
to civil enforcement actions from the state agencies and perhaps the EPA,
including monetary penalties, injunctions, conditions or restrictions on
operations, and, potentially, criminal enforcement actions or federally
authorized citizen suits.

On June 17, 1999, the EPA published in the Federal Register a final MACT
standard under Section 112 of the Clean Air Act to limit emissions of Hazardous
Air Pollutants ("HAPs") from oil and natural gas production as well as from
natural gas transmission and storage facilities. The MACT standard requires that
affected facilities reduce their emissions of HAPs by 95%, and this will affect
our various large dehydration units and potentially some of our storage vessels.
This new standard will require that we achieve this reduction by either process
modifications or installing new emissions control technology. The

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MACT standard will affect us and our competitors in varying degrees. The rule
allows most affected sources until at least June 2002 to comply with the
requirements. While additional capital costs are likely to result from this rule
or other potential air regulations, we believe that these changes will not have
a material adverse effect on our business, financial position or results of
operations.

Our operations generate wastes, including some hazardous wastes, that are
subject to the Resource Conservation and Recovery Act ("RCRA"), as amended and
comparable state laws. However, RCRA currently exempts many natural gas
gathering and processing plant wastes from being subject to hazardous waste
requirements. Specifically, RCRA excludes from the definition of hazardous
waste, wastes associated with the exploration, development, or production of
crude oil, natural gas or geothermal energy. Unrecovered petroleum product
wastes, however, may still be regulated under RCRA as solid waste. Moreover,
ordinary industrial wastes, such as paint wastes, waste solvents, laboratory
wastes, and waste compressor oils, may be regulated. Natural gas and NGLs
transported in pipelines also have the potential to generate some hazardous
wastes. Although we believe it is unlikely that the RCRA exemption will be
repealed in the near future, repeal would increase costs for waste disposal and
environmental remediation at our facilities. Past operations are identified from
time to time as having used polychlorinated biphenyls ("PCBs"), for example, in
plant air compressor systems, and when identified we are required to address or
remediate such a system that might contain PCBs in compliance with the Toxic
Substances Control Act, including any contamination that might be associated
with a release from that system.

Our operations could incur liability under the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), also
known as "Superfund," and comparable state laws or other federal laws regardless
of our fault, in connection with the disposal or other release of hazardous
substances or wastes, including those arising out of historical operations
conducted by our predecessors. If we were to incur liability under CERCLA, we
could be subject to joint and several liability for the costs of cleaning up
hazardous substances, for damages to natural resources and for the costs of
certain health studies.

We currently own or lease, and have in the past owned or leased, numerous
properties that for many years have been used for the measurement, gathering,
field compression and processing of natural gas and NGLs. Although we used
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or wastes may have been disposed of or released on or under the
properties owned or leased by us or on or under other locations where such
wastes have been taken for disposal. In addition, some of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed on them may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously disposed
wastes (including waste disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination, whether from prior
owners or operators or other historic activities or spills) or to perform
remedial plugging or pit closure operations to prevent future contamination, in
some instances regardless of fault or the amount of waste we sent to the site.

EPA Region VIII issued a RCRA administrative cleanup order in 1995 with
respect to the operation of the Weld County Waste Disposal, Inc. site near Fort
Lupton Colorado, and in 1997 one of our predecessors was identified along with
other entities as a potentially responsible party for this site. We are not
aware of administrative activity at this site in the last two years. In
addition, we have various ongoing remedial matters related to historical
operations similar to others in the industry, for the reasons generally
described above. These are typically managed in conjunction with the relevant
state or federal agencies to address specific conditions, and in some cases are
the responsibility of other entities based upon contractual obligations related
to the assets. In April 1999, we acquired the midstream natural gas gathering
and processing assets of Union Pacific Resources located in several states,
which include 18 natural gas plants and 365 gathering facility sites. We have
entered into an agreement for pre-April 1999 soil and ground water conditions
identified as part of this transaction to a third party environmental/insurance
partnership for a one-time premium payment subject to certain deductibles. With
respect to these identified environmental conditions, the environmental partner
has assumed liability and
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management responsibility for environmental remediation, and the insurance
partner is providing financial management, program oversight, remediation cost
cap insurance coverage for a 30 year term, and pollution legal liability
coverage for a 20 year term. While we could face liability in the event of
default, we believe this innovative approach can promote pro-active site cleanup
and closure, reduce internal resource needs for managing remediation, and may
improve the marketability of assets based on transferability of this insurance
coverage. Also, in August 1996, we acquired certain gas gathering and processing
assets in three states from Mobil Corporation. Under the terms of the asset
purchase agreement, Mobil has retained the liabilities and costs related to
various pre-August 1996 environmental conditions that were identified with
respect to those assets. Mobil has formulated or is in the process of developing
plans to address certain of these conditions, which we will review and monitor
as clean-up activities proceed.

Our operations can result in discharges of pollutants to waters. The
Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), also known as
the Clean Water Act, and analogous state laws impose restrictions and strict
controls regarding the discharge of pollutants, including NGLs or unpermitted
wastes, into state waters or waters of the United States. The unpermitted
discharge of pollutants such as from spill or leak incidents are prohibited. The
FWPCA and regulations implemented thereunder also prohibit discharges of fill
material and certain other activities in wetlands unless authorized by an
appropriately issued permit. Any unexpected release of NGLs or condensates from
our systems or facilities could result in significant remedial obligations as
well as FWPCA-related fines or penalties.

We make expenditures in connection with environmental matters as part of
our normal operations and capital expenses. For each of 2000 and 2001, we
estimate that our expensed and capital-related costs will be approximately $13
million. It should be noted, however, that stricter laws and regulations, new
interpretations of existing laws and regulations, or new information or
developments could significantly increase our compliance costs and remediation
obligations.

We are subject to inherent environmental and safety risks related to our
handling of natural gas and NGL products and historical industry waste disposal
practices. We cannot assure you that we will not incur material environmental
costs and liabilities. We believe, based on our current knowledge, that we are
generally in substantial compliance with all of our necessary and material
permits, and that we are generally in substantial compliance with applicable
material environmental and safety regulations. We also use contractual measures,
such as the environmental/insurance partnership discussed above, where
appropriate to mitigate environmental claims or losses but, in the event of a
default, we could be exposed to these claims. Insurance provisions and internal
reserves are also used or applied where warranted to help mitigate the effect
from possible environmental costs and liabilities. Based on current information
and taking into account protective mechanisms mentioned here, we do not believe
that compliance with federal, state or local environmental laws and regulations
will have a material adverse effect on our business, financial position or
results of operations. In addition, we believe that the various environmental
activities in which we are presently engaged are not expected to materially
interrupt or diminish our operational ability to gather, process, and transport
natural gas and NGLs. We cannot assure you, however, that future events, such as
changes in existing laws, the promulgation of new laws, or the development or
discovery of new facts or conditions will not cause us to incur significant new
costs.

Our natural gas gathering pipelines and processing plants in Alberta,
Canada operate under permits from and are regulated by Alberta Environment. Our
West Doe natural gas gathering pipeline, which crosses the Alberta/British
Columbia border, is regulated by the National Energy Board in consultation with
the Canadian Environmental Assessment Agency.

EMPLOYEES

As of June 30, 2000, we had approximately 2,550 employees. We are a party
to two collective bargaining agreements which cover an aggregate of
approximately 180 of our employees and are bound to negotiate in good faith
toward collective bargaining agreements with two other collective bargaining
units which cover an aggregate of approximately 80 employees. We believe our
relations with our employees are good.

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DESCRIPTION OF THE NOTES

The following description of the % notes and the % notes is only a
summary and is not intended to be comprehensive. The description should be read
together with the description of the general terms and provisions of Debt
Securities provided under the caption "Description of Debt Securities" in the
accompanying prospectus. We refer to the % notes and the % notes as the
"Notes" in this section.

GENERAL

The % notes will be limited in principal amount to $ and the %
notes will be limited in principal amount to $ , and each will be issued as
a series of Debt Securities under the Indenture dated as of August , 2000
between us and The Chase Manhattan Bank, as Trustee.

The entire principal amount of the % notes will mature and become due and
payable, together with any accrued and unpaid interest, on August , . The
entire principal amount of the % notes will mature and become due and payable,
together with any accrued and unpaid interest, on August , .

The Notes will not be subject to any sinking fund provision.

INTEREST

Each series of Notes will bear interest from August , 2000 at the annual
rate for that series stated on the cover page of this prospectus supplement. We
will pay interest semiannually on February and August of each year,
beginning February , 2001, to each person in whose name the Notes are
registered at the close of business on the fifteenth calendar day before the
relevant interest payment date. The amount of interest payable will be computed
on the basis of a 360-day year of twelve 30-day months. In the event that any
date on which interest is payable is not a Business Day, we will pay that
interest on the next Business Day without any interest or other payment due to
the delay.

OPTIONAL REDEMPTION

We will have the right to redeem each series of the Notes, in whole or in
part at any time, at a redemption price equal to the greater of (1) 100% of the
principal amount of the Notes of such series to be redeemed and (2) the sum of
the present values of the remaining scheduled payments of principal and interest
on such series of Notes (exclusive of interest accrued to the redemption date)
discounted to the redemption date on a semiannual basis (assuming a 360-day year
consisting of twelve 30-day months) at the Treasury Rate plus basis points,
plus, in either case, accrued and unpaid interest on the principal amount being
redeemed to such redemption date.

"Comparable Treasury Issue" means the United States Treasury security
selected by the Quotation Agent as having a maturity comparable to the remaining
term of the series of Notes to be redeemed that would be utilized, at the time
of selection and in accordance with customary financial practice, in pricing new
issues of corporate debt securities of comparable maturity to the remaining term
of such series of Notes.

"Comparable Treasury Price" means with respect to any redemption date for a
series of Notes (1) the average of the Reference Treasury Dealer Quotations for
such redemption date, after excluding the highest and lowest such Reference
Treasury Dealer Quotations, or (2) if the Trustee obtains fewer than two such
Reference Treasury Dealer Quotations, the average of all such quotations.

"Quotation Agent" means the Reference Treasury Dealers appointed by us.

"Reference Treasury Dealer" means each of Merrill Lynch Government
Securities Inc. and J.P. Morgan Securities Inc. and their respective successors;
provided, however, that if any of the foregoing shall cease to be a primary U.S.
Government securities dealer in New York City (a "Primary Treasury Dealer"), we
will substitute therefor another Primary Treasury Dealer.

S-47
<PAGE> 48

"Reference Treasury Dealer Quotations" means, with respect to each
Reference Treasury Dealer and any redemption date, the average, as determined by
the Trustee, of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) quoted in
writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York
City time, on the third Business Day preceding such redemption date.

"Treasury Rate" means, with respect to any redemption date, (1) the yield,
under the heading which represents the average for the immediately preceding
week, appearing in the most recently published statistical release designated
"H.15 (519)" or any successor publication which is published weekly by the Board
of Governors of the Federal Reserve System and which establishes yields on
actively traded United States Treasury securities adjusted to constant maturity
under the caption "Treasury Constant Maturities," for the maturity corresponding
to the Comparable Treasury Issue (if no maturity is within three months before
or after the maturity date of the series of Notes to be redeemed, yields for the
two published maturities most closely corresponding to the Comparable Treasury
Issue shall be determined, and the Treasury Rate shall be interpolated or
extrapolated from such yields on a straight-line basis, rounding to the nearest
month) or (2) if such release (or any successor release) is not published during
the week preceding the calculation date or does not contain such yields, the
rate per year equal to the semiannual equivalent yield to maturity of the
Comparable Treasury Issue, calculated using a price for the Comparable Treasury
Issue (expressed as a percentage of its principal amount) equal to the
Comparable Treasury Price for such redemption date. The Treasury Rate will be
calculated on the third Business Day preceding the redemption date.

REDEMPTION PROCEDURES

We will provide not less than 30 nor more than 60 days' notice mailed to
each registered holder of the series of Notes to be redeemed. If the redemption
notice is given and funds deposited as required, then interest will cease to
accrue on and after the redemption date on the Notes or portions of such Notes
called for redemption. In the event that any redemption date is not a Business
Day, we will pay the redemption price on the next Business Day without any
interest or other payment due to the delay.

RANKING

The Notes will be our direct, unsecured and senior obligations. The Notes
of each series will rank equal in priority with the Notes of the other series
and with all of our other unsecured and senior indebtedness and senior in right
of payment to all of our existing and future subordinated debt. At June 30,
2000, we had outstanding approximately $2,585 million of unsecured and senior
indebtedness. The Indenture contains no restrictions on the amount of additional
indebtedness that we may issue under it.

DENOMINATIONS

The Notes will be issuable in denominations of $1,000 and integral
multiples of $1,000.

DEFEASANCE AND COVENANT DEFEASANCE

The Notes will be subject to Defeasance and Covenant Defeasance as
described in the Indenture. See "Description of Debt Securities -- Defeasance
and Covenant Defeasance" in the accompanying prospectus.

BOOK-ENTRY ONLY ISSUANCE -- THE DEPOSITORY TRUST COMPANY

The Depository Trust Company ("DTC") will act as the initial securities
depositary for the Notes of each series. The Notes of each series will be
initially issued as fully registered securities registered in the name of Cede &
Co., DTC's nominee. One or more fully registered global certificates will be
issued, representing the total principal amount of the Notes of each series, and
will be deposited with the Trustee as custodian for DTC.

S-48
<PAGE> 49

DTC is a limited-purpose trust company organized under the New York Banking
Law, a "banking organization" within the meaning of the New York Banking Law, a
member of the Federal Reserve System, a "clearing corporation" within the
meaning of the New York Uniform Commercial Code, and a "clearing agency"
registered pursuant to the provisions of Section 17A of the Securities Exchange
Act of 1934, as amended. DTC holds securities that its participants
("participants") deposit with DTC. DTC also facilitates the settlement among
participants of securities transactions, such as transfers and pledges, in
deposited securities through electronic computerized book-entry changes in
participants' accounts, thereby eliminating the need for physical movement of
securities certificates. Direct participants include securities brokers and
dealers, banks, trust companies, clearing corporations and certain other
organizations ("direct participants"). DTC is owned by a number of its direct
participants and by the New York Stock Exchange, Inc., the American Stock
Exchange, Inc., and the National Association of Securities Dealers, Inc. Access
to the DTC system is also available to others such as securities brokers and
dealers, banks and trust companies that clear through or maintain a custodial
relationship with a direct participant, either directly or indirectly ("indirect
participants"). The rules applicable to DTC and its participants are on file
with the Securities and Exchange Commission.

Purchases of Notes within the DTC system must be made by or through direct
participants, which will receive a credit for the Notes on DTC's records. The
ownership interest of each actual purchaser of Notes ("beneficial owner") is in
turn to be recorded on the direct and indirect participants' records. Beneficial
owners will not receive written confirmation from DTC of their purchases, but
beneficial owners are expected to receive written confirmations providing
details of the transactions, as well as periodic statements of their holdings,
from the direct or indirect participants through which the beneficial owners
entered into the transaction. Transfers of ownership interests in the Notes are
to be accomplished by entries made on the books of participants acting on behalf
of beneficial owners. Beneficial owners will not receive certificates
representing their ownership interests in the Notes, except in the event that
use of the book-entry system for the Notes is discontinued.

To facilitate subsequent transfers, all Notes deposited by participants
with DTC are registered in the name of DTC's partnership nominee, Cede & Co. The
deposit of Notes with DTC and their registration in the name of Cede & Co.
effect no change in beneficial ownership. DTC has no knowledge of the actual
beneficial owners of the Notes. DTC's records reflect only the identity of the
direct participants to whose accounts such Notes are credited, which may or may
not be the beneficial owners. The participants will remain responsible for
keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to direct
participants, by direct participants to indirect participants, and by direct
participants and indirect participants to beneficial owners will be governed by
arrangements among them, subject to any statutory or regulatory requirements as
may be in effect from time to time.

Redemption notices will be sent to DTC. If less than all of the Notes are
being redeemed, DTC will reduce the amount of interest of each direct
participant in the Notes in accordance with its procedures.

Neither DTC nor Cede & Co. will consent or vote with respect to Notes.
Under its usual procedures, DTC would mail an Omnibus Proxy to us as soon as
possible after the record date. The Omnibus Proxy assigns Cede & Co.'s
consenting or voting rights to those direct participants to whose account Notes
are credited on the record date (identified in a listing attached to the Omnibus
Proxy).

Payments on the Notes will be made to Cede & Co., as nominee of DTC. DTC's
practice is to credit direct participants' accounts, upon DTC's receipt of funds
and corresponding detailed information, on the relevant payment date in
accordance with their respective holdings shown on DTC's records. Payments by
participants to beneficial owners will be governed by standing instructions and
customary practices, as is the case with securities held for the account of
customers in bearer form or registered in "street name," and will be the
responsibility of such participants and not of DTC or us, subject to any
statutory or regulatory requirements as may be in effect from time to time.
Payment to Cede & Co. is the responsibility of our company or of the payment
agent, disbursement of such payments to direct

S-49
<PAGE> 50

participants is the responsibility of Cede & Co. and disbursement of such
payments to the beneficial owners is the responsibility of direct and indirect
participants.

Except as provided herein, a beneficial owner of an interest in a global
Note will not be entitled to receive physical delivery of Notes. Accordingly,
each beneficial owner must rely on the procedures of DTC to exercise any rights
under the Notes. The laws of some jurisdictions require that certain purchasers
of securities take physical delivery of securities in definitive form. Such laws
may impair the ability to transfer beneficial interests in a global Note.

DTC may discontinue providing its services as securities depositary with
respect to either series of Notes at any time by giving reasonable notice to us.
Under such circumstances, in the event that a successor securities depositary is
not obtained within 90 days, certificates representing such series of Notes will
be printed and delivered to the holders of record. Additionally, we may decide
to discontinue use of the system of book-entry transfers through DTC (or a
successor securities depositary) with respect to either series of Notes. In that
event, certificates for such series of Notes will be printed and delivered to
the holders of record.

The information in this section concerning DTC and DTC's book-entry system
has been obtained from sources that we believe to be reliable, but neither we
nor any Underwriter takes any responsibility for its accuracy. We have no
responsibility for the performance by DTC or its participants of their
respective obligations, including obligations that they have under the rules and
procedures that govern their operations.

UNDERWRITING

Subject to the terms and conditions of an underwriting agreement dated
August , 2000, between us and the several underwriters named below, for whom
Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities
Inc. are acting as representatives, we have agreed to sell to each of the
underwriters named below and each of the underwriters has severally agreed to
purchase from us the respective principal amount of each series of notes set
forth opposite its name below:

<TABLE>
<CAPTION>
PRINCIPAL PRINCIPAL
AMOUNT AMOUNT
OF OF
UNDERWRITER % NOTES % NOTES
------------------------------------------------------------ --------- ---------
<S> <C> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated...................................
J.P. Morgan Securities Inc..................................
Banc of America Securities LLC..............................
Chase Securities Inc........................................
Lehman Brothers Inc.........................................
Morgan Stanley & Co. Incorporated...........................
-------- --------
Total............................................. $
======== ========
</TABLE>

In the underwriting agreement, the underwriters have agreed, subject to
certain conditions, to purchase all of the notes if any of the notes are
purchased.

The underwriters propose initially to offer each series of notes to the
public at the initial public offering price set forth on the cover page of this
prospectus supplement and to certain dealers at that price less a concession not
in excess of % of the principal amount of the % notes and % of the
principal amount of the % notes. The underwriters may allow, and those dealers
may reallow, a discount not in excess of % of the principal amount of the %
notes and % of the principal amount of the % notes to certain other dealers.
After the initial public offering, the public offering price, selling concession
and discount with respect to each series of notes may be changed.

S-50
<PAGE> 51

The notes will not be listed on any securities exchange, and there can be
no assurance that there will be a secondary market for the notes. From time to
time the underwriters may make a market in the notes. However, at this time no
determination has been made as to whether or not the underwriters will make a
market in the notes.

The underwriters may purchase and sell each series of notes in the open
market in connection with the offering. Those transactions may include
over-allotment and stabilizing transactions and purchases to cover syndicate
short positions created in connection with the offering. Stabilizing
transactions consist of certain bids or purchases for the purpose of preventing
or retarding a decline in the market price of each series of notes. Syndicate
short positions involve the sale by the underwriters of a greater principal
amount of notes than they are required to purchase from us in the offering. The
underwriters also may impose a penalty bid, by which selling concessions allowed
to syndicate members or other broker dealers with respect to the securities sold
in the offering for their account may be reclaimed by the syndicate if those
notes are repurchased by the syndicate in stabilizing or covering transactions.
These activities may stabilize, maintain or otherwise affect the market price of
each series of notes, which may be higher than the price that might otherwise
prevail in the open market. These activities, if commenced, may be discontinued
at any time.

We estimate that our expenses in connection with this offering, excluding
underwriting discounts and commissions, will be approximately $5.0 million. The
underwriters have agreed to reimburse us for certain expenses of the offering.

We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933 or to contribute to
payments the underwriters may be required to make in respect of such
liabilities.

Certain of the underwriters and their affiliates engage in transactions
with, and, from time to time, have performed services for, us or certain of our
affiliates in the ordinary course of business and may do so in the future.

VALIDITY OF THE NOTES

The validity of the notes will be passed upon for us by Vinson & Elkins
L.L.P., Houston, Texas and for the underwriters by Sullivan & Cromwell, New
York, New York.

S-51
<PAGE> 52

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PRO FORMA

DUKE ENERGY FIELD SERVICES, LLC (THE "COMPANY")
Unaudited Pro Forma Balance Sheet as of June 30, 2000..... F-3
Notes to the Unaudited Pro Forma Balance Sheet............ F-4
Unaudited Pro Forma Income Statement for the Year Ended
December 31, 1999...................................... F-5
Unaudited Pro Forma Income Statement for the Six Months
Ended June 30, 2000.................................... F-6
Notes to the Unaudited Pro Forma Income Statements........ F-7

HISTORICAL

DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES (THE
"PREDECESSOR COMPANIES")
Independent Auditors' Report.............................. F-9
Combined Balance Sheets at December 31, 1998 and 1999..... F-10
Combined Statements of Income for the Years Ended December
31, 1997, 1998 and 1999................................ F-11
Combined Statements of Equity for the Years Ended December
31, 1997, 1998 and 1999................................ F-12
Combined Statements of Cash Flows for the Years Ended
December 31, 1997, 1998 and 1999....................... F-13
Notes to Combined Financial Statements.................... F-14
Consolidated Balance Sheets as of December 31, 1999 and
June 30, 2000 (Unaudited).............................. F-29
Unaudited Consolidated Statements of Income for the Six
Months Ended June 30, 1999 and 2000.................... F-30
Unaudited Consolidated Statements of Equity for the Six
Months Ended June 30, 2000............................. F-31
Unaudited Consolidated Statements of Cash Flows for the
Six Months Ended June 30, 1999 and 2000................ F-32
Notes to the Unaudited Consolidated Financial
Statements............................................. F-33

PHILLIPS GAS COMPANY ("GPM")
Report of Independent Auditors............................ F-40
Consolidated Balance Sheets at December 31, 1998 and
1999................................................... F-41
Consolidated Statements of Income for the Years Ended
December 31, 1997, 1998 and 1999....................... F-42
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1998
and 1999............................................... F-43
Consolidated Statements of Changes in Stockholders'
Equity/(Deficit) for the Years Ended December 31, 1997,
1998 and 1999.......................................... F-44
Notes to Financial Statements............................. F-45
Unaudited Consolidated Statements of Income for the Three
Months Ended March 31, 1999 and 2000................... F-54
Unaudited Consolidated Statements of Cash Flows for the
Three Months Ended March 31, 1999 and 2000............. F-55
Notes to Financial Statements............................. F-56

UP FUELS DIVISION OF UNION PACIFIC RESOURCES GROUP INC. ("UP
FUELS")
Report of Independent Public Accountants.................. F-58
Independent Auditors Report............................... F-59
Combined Statements of Income for the Years Ended December
31, 1997 and 1998 and the Quarter Ended March 31,
1999................................................... F-60
Combined Statements of Cash Flows for the Years Ended
December 31, 1997 and 1998 and the Quarter Ended March
31, 1999............................................... F-61
Notes to Combined Financial Statements.................... F-62
</TABLE>

F-1
<PAGE> 53

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

The following unaudited pro forma financial statements (the "Unaudited Pro
Forma Financial Statements") of Duke Energy Field Services, LLC were derived by
the application of pro forma adjustments to historical combined and consolidated
financial statements included elsewhere in this prospectus supplement. On March
31, 2000, the Duke Energy and Phillips midstream natural gas businesses were
contributed to Duke Energy Field Services, LLC. Such contribution included the
general partner of TEPPCO as well as certain midstream natural gas assets of
Conoco, Inc. and Mitchell Energy & Development Corp. which were acquired
immediately prior to the contribution. In connection with the contributions,
distributions of $1,219.8 million and $1,524.5 million were made to Phillips and
Duke Energy, respectively. The distributions were funded through the issuance of
commercial paper. The contributions, issuance of commercial paper and
distributions have been reflected in the June 30, 2000 historical balance sheet
of Duke Energy Field Services, LLC. The Unaudited Pro Forma Balance Sheet gives
effect to the subsequent refinancing of a portion of the commercial paper
through the issuance of the $1,500 million of notes pursuant to this prospectus
supplement (the "Notes Offering") and the issuance of an aggregate of $300
million of preferred membership interests in Duke Energy Field Services, LLC to
affiliates of Duke Energy and Phillips, which occurred in August 2000 (the
"Preferred Financing") as if each had occurred on June 30, 2000. All of the
events above are referred to collectively as the "Transactions."

The Unaudited Pro Forma Income Statements give effect to i) the
Transactions and ii) acquisition of the midstream natural gas business of Union
Pacific Resources (the "UP Fuels Acquisition"), which occurred March 31, 1999,
as if such transactions were consummated as of January 1, 1999.

The adjustments are described in the accompanying Notes to the Unaudited
Pro Forma Balance Sheet and the Notes to the Unaudited Pro Forma Income
Statements. The Unaudited Pro Forma Financial Statements should not be
considered indicative of the actual results that would have been achieved had
the Transactions or the UP Fuels Acquisition been consummated on the dates or
for the period indicated and do not purport to indicate balances or results of
operations as of any future date or for any future period. The Unaudited Pro
Forma Financial Statements should be read in conjunction with the historical
combined and consolidated financial statements of the Predecessor Company, UP
Fuels, and GPM and the notes thereto included elsewhere in the prospectus
supplement.

F-2
<PAGE> 54

DUKE ENERGY FIELD SERVICES, LLC

UNAUDITED PRO FORMA BALANCE SHEET
AS OF JUNE 30, 2000
(IN THOUSANDS)

<TABLE>
<CAPTION>
COMPANY
HISTORICAL ADJUSTMENTS(1) PRO FORMA
----------- -------------- ----------
<S> <C> <C> <C>
ASSETS

CURRENT ASSETS:
Cash and cash equivalents....................... $ 2,593 $ -- $ 2,593
Accounts receivable:
Customers, net............................... 722,451 -- 722,451
Affiliates................................... 157,606 -- 157,606
Other........................................ 41,448 -- 41,448
Inventories..................................... 52,566 -- 52,566
Notes receivable................................ 6,502 -- 6,502
Other........................................... 3,111 -- 3,111
---------- ----------- ----------
Total current assets.................... 986,277 -- 986,277
PROPERTY, PLANT AND EQUIPMENT, NET................ 4,441,160 -- 4,441,160
INVESTMENT IN AFFILIATES.......................... 276,443 -- 276,443
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net........ 101,970 -- 101,970
Goodwill, net................................... 84,735 84,735
OTHER NONCURRENT ASSETS........................... 85,202 14,375(1) 98,677
(900)(2)
---------- ----------- ----------
TOTAL ASSETS............................ $5,975,787 $ 13,475 $5,989,262
========== =========== ==========

LIABILITIES AND EQUITY

CURRENT LIABILITIES:
Accounts payable:
Trade........................................ $ 790,865 $ -- $ 790,865
Affiliates................................... 68,423 -- 68,423
Other........................................ 40,599 -- 40,599
Accrued taxes other than income................. 17,693 -- 17,693
Advances, net................................... 80,879 -- 80,879
Short-term debt................................. 2,585,290 (1,485,625)(3)
(300,000)(4) 799,665
Other........................................... 31,904 -- 31,904
---------- ----------- ----------
Total current liabilities............... 3,615,653 (1,785,625) 1,830,028
LONG TERM DEBT.................................... -- 1,500,000(3) 1,500,000
OTHER LONG TERM LIABILITIES....................... 38,923 38,923
EQUITY............................................ 2,321,211 300,000(4)
(900)(2) 2,620,311
---------- ----------- ----------
TOTAL LIABILITIES AND EQUITY...................... $5,975,787 $ 13,475 $5,989,262
========== =========== ==========
</TABLE>

See Notes to the Unaudited Pro Forma Balance Sheet.

F-3
<PAGE> 55

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO THE UNAUDITED PRO FORMA BALANCE SHEET
AS OF JUNE 30, 2000
(IN THOUSANDS)

In December 1999, Duke Energy Field Services, LLC (Field Services LLC or
the Company) was formed to facilitate the combination of the midstream natural
gas businesses of Duke Energy and Phillips Petroleum Company (the
"Combination").

The Combination occurred on March 31, 2000. As part of the Combination,
distributions of $1,524,519 and $1,219,800 to Duke Energy and Phillips,
respectively, were paid. In addition to contributing its midstream natural gas
business, Duke Energy contributed the general partner of TEPPCO Partners, L.P. a
publicly traded limited partnership ("TEPPCO General Partner") and the
mid-continent midstream natural gas assets of Conoco, Inc. and Mitchell Energy &
Development Corp. acquired immediately prior to the Combination. On April 3,
2000 the Company borrowed $2,790,900 in commercial paper to fund the
distributions and fund working capital.

The Combination was accounted for as a purchase business combination in
accordance with Accounting Principles Board Opinion (APB) No. 16 "Accounting for
Business Combinations." The Predecessor Company was the acquiror of Phillips'
midstream natural gas business ("GPM") in the Combination.

The following Notes to the Unaudited Pro Forma Balance Sheet describe the
adjustments to June 30, 2000 historical balances to give effect to the Notes
Offering, the Preferred Financing and related transactions.

1. The pro forma financial data have been derived by the application of pro
forma adjustments to the historical financial statements of the Company for the
period noted. The sources and uses of funds are as follows:

<TABLE>
<CAPTION>
TOTAL
----------
<S> <C>
Sources of funds:
Proceeds from the Preferred Financing..................... $ 300,000
Proceeds from the Notes Offering.......................... 1,500,000
----------
Total sources..................................... $1,800,000
----------
Uses of funds:
Paydown of short-term debt (commercial paper)............. $1,785,625
Underwriter and other transaction fees.................... 14,375
----------
Total uses........................................ $1,800,000
----------
Net adjustment to cash.................................... $ --
==========
</TABLE>

2. Reflects the write-off of a portion of the fees associated with the
revolving credit facility, which will be reduced from $2,800,000 to $1,000,000
upon pay-down of short-term debt (commercial paper) with the proceeds of the
Preferred Financing and the Notes Offering.

3. To record the Notes Offering and application of the net proceeds of
$1,485,625 to reduce short-term debt. The Notes Offering includes notes with two
separate maturities with varying terms and assumes a weighted average interest
rate of 8%.

4. To record the issuance of the preferred membership interests in our
Company to affiliates of Duke Energy and Phillips in the Preferred Financing and
application of the proceeds to reduce short-term debt.

F-4
<PAGE> 56

DUKE ENERGY FIELD SERVICES, LLC

UNAUDITED PRO FORMA INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREDECESSOR CONOCO/
COMPANY UP FUELS GPM MITCHELL TEPPCO GP
HISTORICAL ACQUISITION(1) HISTORICAL ACQUISITION(2) CONTRIBUTION(3)
----------- -------------- ---------- -------------- ---------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum products........ $3,310,260 $228,600 $1,501,178 $228,889 $
Transportation, storage and processing............. 148,050 69,324 88,279 -- --
---------- -------- ---------- -------- ------
Total operating revenues..................... 3,458,310 297,924 1,589,457 228,889 --

COSTS AND EXPENSES
Natural gas and petroleum products................. 2,965,297 252,880 1,148,910 187,689 --
Operating and maintenance.......................... 181,392 22,478 176,864 12,400 --
Depreciation and amortization...................... 130,788 15,125 80,458 6,200 --
General and administrative......................... 73,685 6,965 15,560 -- --
Net (gain) loss on sale of assets.................. 2,377 (907) -- --
---------- -------- ---------- -------- ------
Total costs and expenses..................... 3,353,539 297,448 1,420,885 206,289 --
---------- -------- ---------- -------- ------

OPERATING INCOME.................................... 104,771 476 168,572 22,600 --

EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES..... 22,502 4,821 1,048 (8,994) 9,300
---------- -------- ---------- -------- ------
EARNINGS BEFORE INTEREST AND
TAXES.............................................. 127,273 5,297 169,620 13,606 9,300
INTEREST EXPENSE.................................... 52,915 35,643 -- --
---------- -------- ---------- -------- ------
EARNINGS BEFORE INCOME TAXES........................ 74,358 5,297 133,977 13,606 9,300
INCOME TAX EXPENSE.................................. 31,029 1,900 52,244 5,170 3,534
---------- -------- ---------- -------- ------
NET INCOME FROM CONTINUING OPERATIONS............... $ 43,329 $ 3,397 $ 81,733 $ 8,436 $5,766
========== ======== ========== ======== ======

ADJUSTMENTS(4) PRO FORMA
-------------- ----------
<S> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum products........ $ $5,268,927
Transportation, storage and processing............. -- 305,653
--------- ----------
Total operating revenues..................... -- 5,574,580
COSTS AND EXPENSES
Natural gas and petroleum products................. -- 4,554,776
Operating and maintenance.......................... -- 393,134
Depreciation and amortization...................... 11,298(5) 243,869
General and administrative......................... -- 96,210
Net (gain) loss on sale of assets.................. -- 1,470
--------- ----------
Total costs and expenses..................... 11,298 5,289,459
--------- ----------
OPERATING INCOME.................................... (11,298) 285,121
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES..... (1,339)(6) 27,338
--------- ----------
EARNINGS BEFORE INTEREST AND
TAXES.............................................. (12,637) 312,459
INTEREST EXPENSE.................................... 95,282(7) 183,840
--------- ----------
EARNINGS BEFORE INCOME TAXES........................ (107,919) 128,619
INCOME TAX EXPENSE.................................. (91,277)(8) 2,600
--------- ----------
NET INCOME FROM CONTINUING OPERATIONS............... $ (16,642) $ 126,019
========= ==========
</TABLE>

See Notes to the Unaudited Pro Forma Income Statements.

F-5
<PAGE> 57

DUKE ENERGY FIELD SERVICES, LLC

UNAUDITED PRO FORMA INCOME STATEMENT
FOR THE SIX MONTHS ENDED JUNE 30, 2000
(IN THOUSANDS)

<TABLE>
<CAPTION>
PREDECESSOR GPM CONOCO/MITCHELL TEPPCO GP
COMPANY HISTORICAL ACQUISITION(2) CONTRIBUTION(3) ADJUSTMENTS(4) PRO FORMA
----------- ---------- --------------- --------------- -------------- ----------
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum
products......................... $3,542,823 $532,762 $57,222 $ -- -- $4,132,807
Transportation, storage and
processing....................... 80,748 9,603 -- -- -- 90,351
---------- -------- ------- ------ --------- ----------
Total operating revenues..... 3,623,571 542,365 57,222 -- -- 4,223,158
COSTS AND EXPENSES
Natural gas and petroleum
products......................... 3,115,037 377,659 46,922 -- -- 3,539,618
Operating and maintenance.......... 140,354 47,285 3,100 -- -- 190,739
Depreciation and amortization...... 105,359 20,700 1,550 -- 2,239(5) 129,848
General and administrative......... 69,976 4,251 -- -- -- 74,227
Net (gain) loss on sale of
assets........................... 337 (88) -- -- -- 249
---------- -------- ------- ------ --------- ----------
Total costs and expenses..... 3,431,063 449,807 51,572 -- 2,239 3,934,681
---------- -------- ------- ------ --------- ----------
OPERATING INCOME.................... 192,508 92,558 5,650 -- (2,239) 288,477
EQUITY EARNINGS (LOSS) OF
UNCONSOLIDATED AFFILIATES.......... 14,707 (250) (895) 4,700 (346)(6) 17,916
---------- -------- ------- ------ --------- ----------
EARNINGS BEFORE INTEREST AND
TAXES.............................. 207,215 92,308 4,755 4,700 (2,585) 306,393
INTEREST EXPENSE.................... 59,851 17,865 -- -- 13,754(7) 91,470
---------- -------- ------- ------ --------- ----------
EARNINGS BEFORE INCOME TAXES........ 147,364 74,443 4,755 4,700 (16,339) 214,923
INCOME TAX EXPENSE (BENEFIT)........ (306,765) 29,110 1,807 1,786 278,362(8) 4,300
---------- -------- ------- ------ --------- ----------
NET INCOME FROM CONTINUING
OPERATIONS......................... $ 454,129 $ 45,333 $ 2,948 $2,914 (294,701) $ 210,623
========== ======== ======= ====== ========= ==========
</TABLE>

See Notes to the Unaudited Pro Forma Income Statements.

F-6
<PAGE> 58

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO UNAUDITED PRO FORMA
INCOME STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 1999 AND THE SIX MONTHS ENDED JUNE 30, 2000
(IN THOUSANDS)

The Company's pro forma financial data have been derived by the application
of pro forma adjustments to the historical financial statements of the
Predecessor Company and other contributed businesses for the period noted. See
Note (1) to the Unaudited Pro Forma Balance Sheet.

1. Reflects the historical operating results of UP Fuels for the three month
period ended March 31, 1999, the date the UP Fuels Acquisition was
consummated by the Predecessor Company.

2. Reflects the results of operations associated with the acquisition of the
Conoco and Mitchell businesses, net of the earnings from the
Ferguson/Burleson joint venture interest exchanged as part of the
consideration for the Conoco and Mitchell businesses.

3. Reflects the equity earnings of TEPPCO General Partnership interest
transferred from Duke Energy.

4. The pro forma adjustments exclude non-recurring expenses directly related to
the Transactions which the Company anticipates will be reflected in the
income statement for the period including the Transactions.

5. The excess purchase cost over the book value of net GPM assets acquired in
the Combination has not yet been fully allocated to individual assets and
liabilities acquired. However, the Company believes a portion will be
allocated to property, plant and equipment and identifiable intangibles,
which will be amortized over 20 years. Given its preliminary estimate of the
allocation of the purchase cost to net assets acquired, management has
estimated a composite life of 20 years.

The adjustment to depreciation and amortization was calculated as follows:

<TABLE>
<CAPTION>
PERIOD ENDED
-------------------------
DECEMBER 31, JUNE 30,
1999 2000
------------ ----------
<S> <C> <C>
Net book value of GPM property at January 1, 1999......... $ 943,302 $ 943,302
Excess purchase price over net assets acquired in
Combination Allocated to property and equipment......... 891,808 891,808
---------- ----------
Subtotal................................................ 1,835,110 1,835,110
Composite life -- 20 years................................ 20 20
Depreciation and amortization calculated.................. 91,756 22,939
Less: GPM historical depreciation and amortization........ (80,458) (20,700)
---------- ----------
Net adjustment............................................ $ 11,298 $ 2,239
========== ==========
</TABLE>

6. Reflects elimination of the equity earnings associated with the Predecessor
Company's investment in Westana, which was sold in February 2000 in
connection with the Combination.

F-7
<PAGE> 59
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO UNAUDITED PRO FORMA
INCOME STATEMENTS--CONTINUED
FOR THE YEAR ENDED DECEMBER 31, 1999 AND THE SIX MONTHS ENDED JUNE 30, 2000
(IN THOUSANDS)

7. The pro forma adjustment to interest expense, net is as follows:

<TABLE>
<CAPTION>
PERIOD ENDED
------------------------
DECEMBER 31, JUNE 30,
1999 2000
------------ ---------
<S> <C> <C>
Estimated interest at a weighted average rate of 8%......... $ 206,823 $ 103,412
Amortization of deferred financing costs over estimated
weighted average life of 7.5 years........................ 1,917 958
--------- ---------
Subtotal.................................................. 208,740 104,370

Less: historical interest expense........................... (88,558) (77,716)
--------- ---------
Incremental interest expense before the issuance of
preferred membership interests............................ 120,182 26,654

Short-term debt paid down with proceeds of the issuance of
preferred membership interests............................ (300,000) (300,000)
Estimated weighted average rate............................. 8% 8%
--------- ---------
Subtotal for the year and six months...................... (24,000) (12,000)

Deferred Fees written off as a result of paydown of
short-term debt for the one year and six months,
respectively.............................................. (900) (900)

Reduction of interest expense resulting from pay-down of
short-term debt........................................... (24,900) (12,900)
--------- ---------

Net adjustment.............................................. $ 95,282 $ 13,754
========= =========
</TABLE>

A .125% increase or decrease in the assumed weighted average interest rate
would change pro forma interest expense and net income by $2,875 after paydown
with the proceeds from issuance of the preferred membership interests in the
Preferred Financing on an annual basis.

8. Upon the conversion to a pass-through entity for income tax purposes (LLC) on
March 31, 2000, substantially all income taxes were eliminated.

F-8
<PAGE> 60

INDEPENDENT AUDITORS' REPORT

Duke Energy Field Services, LLC and Affiliates

We have audited the accompanying combined balance sheets of Duke Energy
Field Services, LLC and Affiliates ("the Predecessor Companies") as of December
31, 1998 and 1999, and the related combined statements of income and equity and
cash flows for each of the three years in the period ended December 31, 1999.
The Predecessor Companies are under common ownership and common management.
These financial statements are the responsibility of the Predecessor Companies'
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material
respects, the combined financial position of the Predecessor Companies as of
December 31, 1998 and 1999, and the combined results of their operations and
their combined cash flows for each of the three years in the period ended
December 31, 1999 in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

February 18, 2000
Denver, Colorado

F-9
<PAGE> 61

DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

COMBINED BALANCE SHEETS
AS OF DECEMBER 31, 1998 AND 1999
(IN THOUSANDS)

<TABLE>
<CAPTION>
1998 1999
---------- ----------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 168 $ 792
Accounts receivable:
Customers (net of allowance for doubtful accounts,
1998, $749 and 1999, $6,743).......................... 155,143 370,139
Affiliates............................................. 57,725 63,927
Other.................................................. 27,246 30,067
Inventories............................................... 23,713 38,701
Notes receivable.......................................... 5,266 13,050
Other..................................................... 531 1,580
---------- ----------
Total current assets.............................. 269,792 518,256
PROPERTY, PLANT AND EQUIPMENT:
Cost...................................................... 1,763,594 3,005,510
Accumulated depreciation and amortization................. (480,296) (596,125)
---------- ----------
Net property, plant, and equipment................ 1,283,298 2,409,385
INVESTMENTS IN AFFILIATES................................... 187,938 343,835
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net.................. 102,382
Goodwill, net............................................. 15,299 85,846
OTHER NONCURRENT ASSETS..................................... 14,511 12,131
---------- ----------
TOTAL ASSETS................................................ $1,770,838 $3,471,835
========== ==========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade.................................................. $ 200,864 $ 353,977
Affiliates............................................. 10,762 62,370
Other.................................................. 5,556 33,858
Accrued taxes other than income........................... 14,194 15,653
Advances, net -- parents.................................. 334,057 1,579,475
Notes payable -- affiliates............................... 540,000 588,880
Other..................................................... 8,976 6,372
---------- ----------
Total current liabilities......................... 1,114,409 2,640,585
DEFERRED INCOME TAXES....................................... 222,007 308,308
NOTE PAYABLE TO PARENT...................................... 101,600 101,600
OTHER LONG TERM LIABILITIES................................. 34,871
COMMITMENTS AND CONTINGENT LIABILITIES
EQUITY:
Common stock.............................................. 3 1
Paid-in capital........................................... 202,523 213,091
Retained earnings......................................... 130,296 173,091
Other comprehensive income................................ 288
---------- ----------
Total equity...................................... 332,822 386,471
---------- ----------
TOTAL LIABILITIES AND EQUITY................................ $1,770,838 $3,471,835
========== ==========
</TABLE>

See Notes to the Combined Financial Statements.

F-10
<PAGE> 62

DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

COMBINED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)

<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
OPERATING REVENUES:
Sales of natural gas and petroleum products............ $1,700,029 $1,469,133 $3,310,260
Transportation and storage of natural gas.............. 41,896 50,097 76,604
Other.................................................. 59,907 65,090 71,446
---------- ---------- ----------
Total operating revenues....................... 1,801,832 1,584,320 3,458,310
---------- ---------- ----------
COSTS AND EXPENSES:
Natural gas and petroleum products..................... 1,468,089 1,338,129 2,965,297
Operating and maintenance.............................. 104,308 113,556 181,392
Depreciation and amortization.......................... 67,701 75,573 130,788
General and administrative............................. 36,023 44,946 73,685
Net (gain) loss on sale of assets...................... (236) (33,759) 2,377
---------- ---------- ----------
Total costs and expenses....................... 1,675,885 1,538,445 3,353,539
---------- ---------- ----------
OPERATING INCOME......................................... 125,947 45,875 104,771
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES.......... 9,784 11,845 22,502
---------- ---------- ----------
EARNINGS BEFORE INTEREST AND TAXES....................... 135,731 57,720 127,273
INTEREST EXPENSE......................................... 51,113 52,403 52,915
---------- ---------- ----------
INCOME BEFORE INCOME TAXES............................... 84,618 5,317 74,358
INCOME TAXES............................................. 33,380 3,289 31,029
---------- ---------- ----------
NET INCOME............................................... $ 51,238 $ 2,028 $ 43,329
========== ========== ==========
</TABLE>

See Notes to the Combined Financial Statements.

F-11
<PAGE> 63

DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

COMBINED STATEMENTS OF EQUITY
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)

<TABLE>
<CAPTION>
ADDITIONAL OTHER
COMMON PAID-IN RETAINED COMPREHENSIVE
STOCK CAPITAL EARNINGS INCOME TOTAL
------ ---------- -------- ------------- --------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1996....... $ 3 $200,326 $77,030 $277,359
Contributions....................
Net income....................... 51,238 51,238
--- -------- -------- ---- --------
BALANCE, DECEMBER 31, 1997....... 3 200,326 128,268 328,597
Contributions.................... 2,197 2,197
Net income....................... 2,028 2,028
--- -------- -------- ---- --------
BALANCE, DECEMBER 31, 1998....... 3 202,523 130,296 332,822
Contributions.................... 10,568 10,568
Net income....................... 43,329 43,329
Other............................ (2) (534) $288 (248)
--- -------- -------- ---- --------
BALANCE, DECEMBER 31, 1999....... $ 1 $213,091 $173,091 $288 $386,471
=== ======== ======== ==== ========
</TABLE>

See Notes to the Combined Financial Statements.

F-12
<PAGE> 64

DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

COMBINED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)

<TABLE>
<CAPTION>
1997 1998 1999
----------- --------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................... $ 51,238 $ 2,028 $ 43,329
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization..................... 67,701 75,573 130,788
Deferred income tax expense....................... 35,823 45,315 86,301
Equity in undistributed earnings.................. (9,784) (11,846) (22,502)
Loss (gain) on sale of assets..................... (236) (33,759) 2,377
Net change in operating assets and liabilities:
Accounts receivable............................... (76,679) 133,461 (175,008)
Inventories....................................... 5,572 1,762 (5,303)
Other current assets.............................. 11,320 10,150 20,356
Accounts payable.................................. 101,763 (177,418) 152,535
Other current liabilities......................... (13,361) (4,857) (4,390)
Other long term liabilities....................... (55,347)
----------- --------- -----------
Net cash provided by operating activities.... 173,357 40,409 173,136
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions and other capital expenditures.......... (121,978) (185,479) (1,570,083)
Investment in affiliates............................. (29,600) (84,884) (62,752)
Affiliate distributions.............................. 10,742 15,051 31,999
Proceeds from sales of assets........................ 2,815 51,687 29,390
----------- --------- -----------
Net cash used in investing activities........ (138,021) (203,625) (1,571,446)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in advances -- parents....... (35,061) 162,514 1,350,054
Notes payable borrowings............................. 48,880
----------- --------- -----------
Net cash flows provided by (used in)
financing activities....................... (35,061) 162,514 1,398,934
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS... 275 (702) 624
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR........... 595 870 168
----------- --------- -----------
CASH AND CASH EQUIVALENTS, END OF YEAR................. $ 870 $ 168 $ 792
=========== ========= ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION --Cash
paid for interest (net of amounts capitalized)....... $ 51,765 $ 52,948 $ 52,915
</TABLE>

See Notes to the Combined Financial Statements.

F-13
<PAGE> 65

DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999

1. ACCOUNTING POLICIES SUMMARY

Principles of Combining -- The accounting policies are presented to assist
the reader in evaluating the combined financial statements of Duke Energy Field
Services, LLC, Duke Energy Field Services, Inc. (DEFSI), Panhandle Field
Services Company (PFSC), Panhandle Gathering Company (PGC), and Duke Energy
Services Canada, Ltd. (DESCL) (together, "Duke Energy Field Services, LLC and
Affiliates" or the Predecessor Companies). The Predecessor Companies are
indirect subsidiaries of Duke Energy Corporation (Duke Energy). During 1999,
PFSC and PGC were contributed to and became wholly-owned subsidiaries of DEFSI.
The resulting December 31, 1999 stockholders' equity (1,000 shares authorized
and issued, $1.00 par value) reflects that of DEFSI and DESCL. Our limited
liability company agreement limits the scope of our business to the midstream
natural gas industry in the United States and Canada, the marketing of natural
gas liquids in Mexico and the transportation, marketing and storage of other
petroleum products.

The Combination -- On December 16, 1999, Duke Energy and Phillips Petroleum
Company
(Phillips) entered into an agreement to combine their United States and Canadian
midstream natural gas gathering, processing and natural gas liquid operations
(the Combination). In connection with the Combination, Duke Energy's midstream
natural gas gathering and processing business was transferred to Duke Energy
Field Services, LLC and the Combination will be accounted for as an acquisition
by the Predecessor Companies of Phillips' midstream business.

Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents -- All liquid investments with maturities at date
of purchase of three months or less are considered cash equivalents.

Inventories -- Inventories are recorded at the lower of cost or market
using the average cost method.

Property, Plant and Equipment -- Property, plant and equipment are stated
at cost, which does not purport to represent replacement or realizable value.
Assets, including goodwill and other intangibles, are evaluated for potential
impairment based on undiscounted cash flows and any impairment recorded is
derived based on discounted cash flows. There was no impairment during 1997,
1998 or 1999. Depreciation of property, plant and equipment is computed using
the straight-line method (see Note 4).

Interest totaling $2.3 million, $1.6 million and $.9 million has been
capitalized on construction projects for 1997, 1998 and 1999, respectively.

Revenue Recognition -- The Predecessor Companies recognize revenues on
sales of natural gas and petroleum products in the period of delivery and
transportation revenues in the period service is provided. An allowance for
doubtful accounts is established based on agings of accounts receivable and the
credit worthiness of our customers. Bad debt expense and writeoffs for each year
presented are not significant.

Equity in Unconsolidated Affiliates -- Investments in 20% to 50% owned
affiliates are accounted for using the equity method. Investments greater than
50% are consolidated unless the Predecessor Companies do not operate these
investments and as a result do not have the ability to exercise control or
control is considered to be temporary (See Note 5).

Derivative Contracts -- The Predecessor Companies use commodity swaps,
futures and option contracts in the conduct of their business. Unrealized gains
and losses associated with activity other than

F-14
<PAGE> 66
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

trading are recognized when the underlying physical transaction is recorded.
Trading activity is marked-to-market and reflected in the statements of income
as sales of natural gas and petroleum products or costs of such.

Significant Customers -- Duke Energy Trading and Marketing, L.L.C. (DETM),
an affiliated company, is a significant customer. Sales to DETM totaled $567
million, $522 million and $684 million during 1997, 1998 and 1999, respectively.

Intangibles Amortization -- Goodwill is amortized over the period of
expected benefit. Goodwill is being amortized on a straight-line basis over 15
years related to the 1991 acquisition of MEGA Natural Gas Company and 20 years
related to the UP Fuels acquisition (see Note 2). Natural gas liquids sales
contracts are amortized on a straight-line basis over the contract lives which
average 15 years.

Environmental Costs -- Environmental expenditures are expensed or
capitalized as appropriate, depending upon the future economic benefit.
Expenditures that relate to an existing condition caused by past operations, and
that do not have future benefit, are expensed. Liabilities for these
expenditures are recorded on an undiscounted basis when environmental
assessments or clean-ups are probable and the costs can be reasonably estimated.
Environmental liabilities at the end of 1998 and 1999 were insignificant.

Gas Imbalance Accounting -- Quantities of natural gas over-delivered or
under-delivered related to imbalance agreements are recorded monthly as
receivables or payables using index prices or the weighted average prices of
natural gas at the plant or system. Generally, these balances are settled with
deliveries of natural gas.

Deferred Income Tax -- The Predecessor Companies follow the asset and
liability method of accounting for income tax. Deferred taxes are provided for
temporary differences in the tax and financial reporting basis of assets and
liabilities. The effect of a change in tax rates on deferred tax assets and
liabilities is recognized in income in the period the rate change is enacted.

Stock Based Compensation -- The Predecessor Companies account for
stock-based compensation using the intrinsic method of accounting. Under this
method, compensation cost, if any, is measured as the excess of the quoted
market price of stock at the date of the grant over the amount an employee must
pay to acquire stock. Restricted stock is recorded as compensation cost over the
requisite vesting period based on the market value on the date of the grant.

Earnings Per Share -- The historical capital structure of the Predecessor
Companies is not representative of the future capital structure of DEFSI (see
Note 2), as all companies were wholly-owned subsidiaries. Accordingly, the
historical net income per share and weighted average number of common shares
outstanding are not shown for any of the periods presented.

Comprehensive Income -- The Predecessor Companies' only item of other
comprehensive income is foreign currency translation.

Recently Issued Accounting Pronouncements -- In June 1998, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133). SFAS 133 establishes standards for derivative instruments, including
certain derivative instruments embedded in other contracts (collectively
referred to as derivatives) and for hedging activities. SFAS 133 requires that
an entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. If
certain conditions are met, a derivative may be specifically designated as (a) a
hedge of the exposure to changes in the fair value of a recognized asset or
liability or an unrecognized firm commitment, (b) a hedge of the exposure to
variable cash flows of a forecasted transaction, or (c) a hedge of the foreign
currency exposure of a net investment in a foreign operation, an unrecognized
firm commitment, an
F-15
<PAGE> 67
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

available-for-sale security, or a foreign-currency-denominated forecasted
transaction. The accounting for changes in the fair value of a derivative (gains
and losses) depends on the intended use of the derivative and the resulting
designation. The Predecessor Companies are required to adopt SFAS 133 on January
1, 2001. The Predecessor Companies have not completed the process of evaluating
the impact that will result from adopting SFAS 133.

2. BUSINESS COMBINATIONS/DISPOSITIONS

In March 1998, the Predecessor Companies sold a fractionator to TEPPCO
Colorado, L.L.C., an indirect, wholly-owned subsidiary of TEPPCO Partners, L.P.
(TEPPCO), of which Duke Energy, through an indirect, wholly-owned subsidiary,
has an equity interest of approximately 18%. The fractionator was sold for $40
million and the Predecessor Companies realized a gain of approximately $38
million.

On March 31, 1999, the Predecessor Companies acquired the assets and
assumed certain liabilities of Union Pacific Fuels, Inc. (UP Fuels), a
wholly-owned subsidiary of Union Pacific Resources Company (UPR), for a total
purchase price of $1.359 billion. The acquisition was accounted for under the
purchase method of accounting, and the assets and liabilities and results of
operations of UP Fuels have been consolidated in the Predecessor Companies'
financial statements since the date of purchase. The purchase price has been
allocated to the assets acquired and liabilities assumed based on estimated fair
value, as follows:

<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
Property, plant and equipment...................... $1,046,316
Partnerships and other joint venture investments... 116,644
Natural gas liquids sales contracts................ 107,771
Goodwill........................................... 75,548
Gas marketing...................................... 104,843
Deferred tax asset................................. 10,200
Net working capital................................ (8,207)
Environmental and other liabilities................ (94,018)
----------
Net.............................................. $1,359,097
==========
</TABLE>

The gas marketing component of UP Fuels was immediately transferred to an
affiliate of Duke Energy after the acquisition at the above fair value. Revenues
and net income for 1998 on a pro forma basis would have increased $1.4 billion
and $54.9 million, respectively, if the acquisition had occurred on January 1,
1998. Revenues and net income for 1999 on a pro forma basis would have increased
$298 million and $2.8 million, respectively, if the acquisition had occurred on
January 1, 1999.

3. INVENTORIES

A summary of inventories by category follows:

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1999
------- -------
(IN THOUSANDS)
<S> <C> <C>
Gas held for resale......................................... $13,202 $18,114
NGLs........................................................ 5,962 18,211
Materials and supplies...................................... 4,549 2,376
------- -------
Total inventories................................. $23,713 $38,701
======= =======
</TABLE>

F-16
<PAGE> 68
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

4. PROPERTY, PLANT AND EQUIPMENT

A summary of property, plant and equipment by classification follows:

<TABLE>
<CAPTION>
DECEMBER 31,
DEPRECIATION -----------------------
RATES 1998 1999
------------ ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Gathering...................................... 4% - 6% $ 923,350 $1,231,050
Processing..................................... 4% 416,572 1,197,993
Transmission................................... 4% 251,079 413,633
Underground storage............................ 2% - 5% 79,875 73,958
General plant.................................. 20% - 33% 36,214 37,614
Construction work in progress.................. 56,504 51,262
---------- ----------
Total property, plant and
equipment.......................... $1,763,594 $3,005,510
========== ==========
</TABLE>

5. INVESTMENTS IN AFFILIATES

The Predecessor Companies have investments in the following businesses
accounted for using the equity method:

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
OWNERSHIP 1998 1999
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Dauphin Island Gathering Partners................... 37.28% $ 96,869 $ 99,878
Mont Belvieu I...................................... 20.00% 40,440
Mobile Bay Processing Partners...................... 28.81% 30,166 35,906
Black Lake Pipeline................................. 50.00% 35,641
Sycamore Gas System General Partnership............. 48.45% 19,344 21,985
Main Pass Oil Gathering............................. 33.33% 15,762 16,967
Ferguson-Burleson................................... 55.00% 23,631
Other affiliates.................................... Various 12,406 54,141
-------- --------
174,547 328,589
Westana Gathering Company........................... 50.00% 13,391 15,246
-------- --------
Total investments in affiliates........... $187,938 $343,835
======== ========
</TABLE>

Dauphin Island Gathering Partners -- Dauphin Island Gathering Partners is a
partnership which owns the Dauphin Island Gathering system and the Main Pass Gas
Gathering system, which are natural gas gathering systems in the Gulf of Mexico.

Mont Belvieu I -- Mont Belvieu I operates a 200 MBbl/d fractionation
facility in the Mont Belvieu, Texas Market Center.

Mobile Bay Processing Partners -- Mobile Bay Processing Partners is a
partnership formed to engage in the financing, ownership, construction and
operation of one or more natural gas processing facilities onshore in Mobile
County, Alabama.

Black Lake Pipeline -- Black Lake Pipeline owns a 317 mile long NGL
pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline
receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are
transported to Mont Belvieu fractionators.

F-17
<PAGE> 69
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

Sycamore Gas System General Partnership -- Sycamore Gas System General
Partnership is a partnership formed for the purpose of constructing, owning and
operating a gas gathering and compression system in Carter County, Oklahoma.

Main Pass Oil Gathering -- Main Pass Oil Gathering is a joint venture whose
primary operation is a crude oil gathering pipeline system of 81 miles in the
Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico.

Ferguson-Burleson -- Ferguson-Burleson operates two independent gas
gathering systems, rich and lean, that are interconnected. The rich gas system
is comprised of over 1,450 miles of gathering lines serving six counties in
South Central Texas. The lean gas system consists of approximately 100 miles of
pipelines in two counties in South Central Texas. We own 55% of the economic
interest in Ferguson-Burleson but have only a 50% voting interest. The operator
of the assets controls the other 50% voting interest and manages the operations
on a daily basis. The Predecessor Companies do not have the ability to control
Ferguson-Burleson and therefore do not consolidate its results.

Equity in earnings amounted to the following for the years ended December
31:

<TABLE>
<CAPTION>
1997 1998 1999
------ ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Dauphin Island Gathering Partners........................ $4,250 $ 7,234 $ 5,974
Mont Belvieu I........................................... 440
Mobile Bay Processing Partners........................... 65 2,307
Black Lake Pipeline...................................... 1,141
Sycamore Gas System General Partnership.................. 261 142
Main Pass Oil Gathering.................................. 1,665 2,598 3,638
Ferguson-Burleson........................................ 5,600
Other affiliates......................................... 3,062 1,279 1,921
------ ------- -------
8,977 11,437 21,163
Westana Gathering Company................................ 807 409 1,339
------ ------- -------
Total equity earnings.......................... $9,784 $11,846 $22,502
====== ======= =======
</TABLE>

Distributions in excess of earnings were $1.0 million, $3.2 million and
$9.5 million in 1997, 1998 and 1999, respectively.

In connection with the Combination, the Predecessor Companies' interest in
Westana Gathering Company was sold in February 2000. Proceeds and loss on sale
approximated $12 million and $4 million, respectively.

F-18
<PAGE> 70
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

The following summarizes combined financial information of unconsolidated
affiliates excluding Westana for the years ended December 31:

<TABLE>
<CAPTION>
1997 1998 1999
------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Income statement:
Operating revenues................................. $54,898 $ 61,618 $ 452,118
Operating expenses................................. 34,281 36,173 374,079
Net income......................................... 21,318 27,878 55,606
Balance sheet:
Current assets..................................... $ 57,926 $ 119,506
Noncurrent assets.................................. 388,562 761,270
Current liabilities................................ (25,671) (113,121)
Noncurrent liabilities............................. (8,094) (14,853)
-------- ---------
Net assets................................. $412,723 $ 752,802
======== =========
</TABLE>

6. TRANSACTIONS WITH AFFILIATES

A summary of transactions with affiliates included in the combined
statements of income follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1997 1998 1999
-------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Sales of natural gas and petroleum products......... $567,800 $536,300 $ 696,700
Natural gas and petroleum products purchased........ 48,900 79,600 128,600
Transportation revenue.............................. 6,400 2,700
Operating expenses -- Billed to affiliates(1)....... 4,200 7,200
General and administrative expenses(1):
Billed to affiliates.............................. 1,200 502
Billed from affiliates............................ 11,700 12,100 19,100
Interest expense.................................... 60,100 60,100 53,900
</TABLE>

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

(1) Operating, general and administrative expenses are allocated to
affiliates based on cost.

As of December 31, 1998 and 1999, the Predecessor Companies had a $101.6
million note payable to Duke Energy, scheduled to mature in 2004 bearing
interest at 8.5%. Additionally, as of December 31, 1999, the Predecessor
Companies had a $540 million note payable to Duke Energy, scheduled to mature
December 31, 2000 bearing interest at prime (8.5% at December 31, 1999),
adjusted quarterly, and a $44.3 million and $4.6 million note payable to Duke
Energy, payable on demand and bearing interest at the Canadian Prime Rate (6.5%
at December 31, 1999), plus fifty basis points, adjusted quarterly.

Intercompany advances do not bear interest. Advances are carried as open
accounts and are not segregated between current and non-current amounts.
Increases and decreases in advances result from the movement of funds to provide
for operations, capital expenditures, and debt payments of Duke Energy and its
subsidiaries. In addition, current income tax balances are recorded in these
accounts. Average intercompany advances payable approximated $117.3 million,
$203.8 million and $1,410 million for 1997, 1998 and 1999, respectively.

Duke Energy supplies the Predecessor Companies with various staff and
support services, including information technology products and services,
payroll, employee benefits, corporate insurance, cash

F-19
<PAGE> 71
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

management, ad valorem taxes, treasury and legal functions. These expenditures
are allocated to the Predecessor Companies using a cost based method of
allocation. Management believes the allocation is reasonable and estimates that
such costs approximate the costs for such services that would have been incurred
on a stand alone basis.

See Notes 5 and 12 for discussion of other specific transactions with
affiliates.

7. INCOME TAXES

The Predecessor Companies' taxable income is included in a consolidated
federal income tax return with Duke Energy. Therefore, income tax has been
provided in accordance with Duke Energy's tax allocation policy, which requires
subsidiaries to calculate federal income tax as if separate taxable income, as
defined, was reported. Foreign income taxes are not material and therefore are
not shown separately.

Income tax as presented in the combined statements of income is summarized
as follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------
1997 1998 1999
------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current:
Federal........................................... $(1,012) $(36,142) $(46,429)
State............................................. (1,431) (5,884) (8,843)
------- -------- --------
Total current............................. (2,443) (42,026) (55,272)
------- -------- --------
Deferred:
Federal........................................... 30,800 38,961 73,201
State............................................. 5,023 6,354 13,100
------- -------- --------
Total deferred............................ 35,823 45,315 86,301
------- -------- --------
Total income tax expense............................ $33,380 $ 3,289 $ 31,029
======= ======== ========
</TABLE>

Total income tax expense differs from the amount computed by applying the
federal income tax rate to earnings before income tax. The reasons for this
difference are as follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1997 1998 1999
------- ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal income tax rate................................ 35.0% 35.0% 35.0%
======= ====== =======
Income tax, computed at the statutory rate............. $29,616 $1,861 $26,025
Adjustments resulting from:
State income tax, net of federal income tax effect... 2,962 186 2,863
Non-deductible amortization and other................ 802 1,242 2,141
------- ------ -------
Total income tax............................. $33,380 $3,289 $31,029
======= ====== =======
</TABLE>

F-20
<PAGE> 72
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

The tax effects of temporary differences that resulted in deferred income
tax assets and liabilities, and a description of the significant items that
created these differences are as follows:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Alternative minimum tax credit carryforward....... $ 20,400 $ 20,400 $ --
Other............................................. 2,300 500 7,600
--------- --------- ---------
Total deferred income tax assets........ 22,700 20,900 7,600
--------- --------- ---------
Property, plant, and equipment.................... (160,200) (209,507) (275,008)
Deferred charges.................................. (900) (15,000) (15,300)
State deferred income tax, net of federal tax
effect.......................................... (14,300) (18,400) (25,600)
--------- --------- ---------
Total deferred income tax liabilities... (175,400) (242,907) (315,908)
--------- --------- ---------
Net deferred income tax liability................. $(152,700) $(222,007) $(308,308)
========= ========= =========
</TABLE>

8. BUSINESS SEGMENTS AND RELATED INFORMATION

The Predecessor Companies operate in two principal business segments as
follows: (1) natural gas gathering, processing, transportation, marketing and
storage, and (2) natural gas liquids fractionation, transportation, marketing
and trading. These segments are separately monitored by management for
performance against its internal forecast and are consistent with the
Predecessor Companies internal financial reporting package. These segments have
been identified based upon the differing products and services, regulatory
environment and the expertise required for these operations. Margin, earnings
before interest, taxes, depreciation and amortization (EBITDA) and earnings
before interest and taxes (EBIT) are the performance measures utilized by
management to monitor the business of each segment. The accounting policies for
the segments are the same as those described in Note 1. Foreign operations are
not material and are therefore not separately identified.

The following table sets forth the Predecessor Companies' segment
information as of and for the years ended December 31, 1997, 1998 and 1999.

<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues:
Natural gas............................................ $1,683,483 $1,497,901 $2,483,197
NGLs................................................... 423,680 309,380 1,365,577
Intersegment(a)........................................ (305,331) (222,961) (390,464)
---------- ---------- ----------
Total operating revenues....................... 1,801,832 1,584,320 3,458,310
---------- ---------- ----------
Margin:
Natural gas............................................ 334,129 243,787 459,843
NGLs................................................... (386) 2,404 33,170
---------- ---------- ----------
Total margin................................... 333,743 246,191 493,013
---------- ---------- ----------
Other operating costs:
Natural gas............................................ 104,072 79,797 182,062
NGLs................................................... -- -- 1,707
Corporate.............................................. 36,023 44,946 73,685
---------- ---------- ----------
Total other operating costs.................... 140,095 124,743 257,454
---------- ---------- ----------
</TABLE>

F-21
<PAGE> 73
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Equity in earnings of unconsolidated affiliates:
Natural gas............................................ 9,784 11,845 20,917
NGLs................................................... 1,585
---------- ---------- ----------
Total equity in earnings of unconsolidated
affiliates................................... 9,784 11,845 22,502
---------- ---------- ----------
EBITDA(b):
Natural gas............................................ 239,841 175,835 298,698
NGLs................................................... (386) 2,404 33,048
Corporate.............................................. (36,023) (44,946) (73,685)
---------- ---------- ----------
Total EBITDA................................... 203,432 133,293 258,061
---------- ---------- ----------
Depreciation and amortization:
Natural gas............................................ 65,593 73,470 119,425
NGLs................................................... 9,073
Corporate.............................................. 2,108 2,103 2,290
---------- ---------- ----------
Total depreciation and amortization............ 67,701 75,573 130,788
---------- ---------- ----------
EBIT:
Natural gas............................................ 174,248 102,365 179,273
NGLs................................................... (386) 2,404 23,975
Corporate.............................................. (38,131) (47,049) (75,975)
---------- ---------- ----------
Total EBIT..................................... 135,731 57,720 127,273
---------- ---------- ----------
Corporate interest expense............................... 51,113 52,403 52,915
---------- ---------- ----------
Income before income taxes:
Natural gas............................................ 174,248 102,365 179,273
NGLs................................................... (386) 2,404 23,975
Corporate.............................................. (89,244) (99,452) (128,890)
---------- ---------- ----------
Total income before income taxes............... $ 84,618 $ 5,317 $ 74,358
---------- ---------- ----------
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------
1998 1999
---------- ----------
<S> <C> <C>
Total assets:
Natural gas............................................... $1,505,111 $2,754,447
NGLs...................................................... 5,137 225,702
Corporate(c).............................................. 260,590 491,686
---------- ----------
Total assets...................................... $1,770,838 $3,471,835
========== ==========
</TABLE>

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

(a) Intersegment sales represent sales of NGLs from the natural gas segment to
the NGLs segment at either index prices or weighted average prices of NGLs.
Both measures of intersegment sales are effectively based on current
economic market conditions.

(b) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense, less
interest income. EBITDA is not a measurement presented in accordance with
generally accepted accounting principles. You should not consider it in
isolation from or as a substitute for net income or cash flow measures
prepared in accordance with generally accepted accounting principles or as a
measure of our profitability or liquidity. EBITDA is

F-22
<PAGE> 74
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

included as a supplemental disclosure because it may provide useful
information regarding our ability to service debt and to fund capital
expenditures. However, not all EBITDA may be available to service debt.

9. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

The Predecessor Companies' operations are subject to the volatility of
commodity prices, particularly that of NGL prices. The Predecessor Companies
manage exposure to risk from existing contractual commitments through forward
contracts, futures and over-the-counter swap agreements (collectively,
"commodity instruments"). Energy commodity forward contracts involve physical
delivery of an energy commodity. Energy commodity futures involve the buying or
selling of natural gas, crude oil (used to hedge NGLs prices) and NGLs at a
fixed price. Over-the-counter swap agreements require the Predecessor Companies
to receive or make payments based on the difference between a specified price
and the actual price of the underlying commodity.

Commodity Instruments -- Trading -- The Predecessor Companies, through a
wholly-owned subsidiary, engage in the trading of NGLs and crude oil commodity
instruments, and therefore experience net open positions. The Predecessor
Companies manage open positions with policies which limit its exposure to market
risk and require daily reporting to management of potential financial exposure.
The weighted-average life of the Predecessor Companies commodity risk portfolio
was approximately 2 months at December 31, 1999. During 1999 net gains of $9.7
million were recognized from trading NGLs and crude oil derivatives. The
Predecessor Companies were not trading NGLs nor crude oil commodity instruments
prior to 1999. As of December 31, 1999, the absolute notional contract quantity
of NGLs and crude oil commodity derivatives held for trading purposes was
5,826,000 and 6,486,500 barrels, respectively.

<TABLE>
<CAPTION>
1999
---------------------
ASSETS LIABILITIES
------- -----------
(IN THOUSANDS)
<S> <C> <C>
Fair value at December 31................................... $10,461 $10,079
Average fair value for the year............................. 8,588 8,359
</TABLE>

Commodity Derivatives -- Non-Trading -- At December 31, 1998 and 1999, the
Predecessor Companies held or issued derivatives that reduce the Predecessor
Companies' exposure to market fluctuations in the price and transportation costs
of natural gas and NGLs. The Predecessor Companies' market exposure arises from
inventory balances and fixed-price purchase and sale commitments that extend for
periods of up to 10 years. Futures and swaps are used to manage and hedge prices
and location risk related to these market exposures. Futures and swaps are also
used to manage margins on offsetting fixed-price purchase or sale commitments
for physical quantities of natural gas and NGLs.

The gains, losses and costs related to those commodity derivatives that
qualify as a hedge are not recognized until the underlying physical transaction
occurs. At December 31, 1998 and 1999, the Predecessor Companies unrealized net
gains (losses) related to commodity derivative hedges was $1.8 million and
$(63.5) million, respectively. As of December 31, 1998 and 1999, the absolute
notional contract quantity of commodity derivatives held for non-trading
purposes was 10.92 and 7.8 billion cubic feet (Bcf) of natural gas and 59,000
and 32,764,000 barrels of crude oil, respectively. Hedging losses in 1999
totaled approximately $34 million.

F-23
<PAGE> 75
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

Market and Credit Risk -- Most futures and swaps are conducted through
either DETM or Duke Energy Merchants (DEM). Under these arrangements the
Predecessor Companies do not have margin requirements.

New York Mercantile Exchange (Exchange) traded futures contracts are
guaranteed by the Exchange and have nominal credit risk. On all other
transactions previously described, the Predecessor Companies are exposed to
credit risk in the event of nonperformance by the counterparties. For each
counterparty, the Predecessor Companies analyze the financial condition prior to
entering into an agreement. The change in market value of exchange-traded
futures contracts other than those conducted through either DETM or DEM require
daily cash settlement in margin accounts with brokers. Swap contracts are
generally settled at the expiration of the contract term and may be subject to
margin requirements with the counterparty.

Gathering, processing, and transportation services are provided to
producers, refiners, and a variety of wholesale and retail customers located in
the Mid-Continent, Gulf Coast and Rocky Mountain areas as well as in Canada. The
principal markets for natural gas marketing services are industrial end-users
and utilities located throughout the United States. The Predecessor Companies
have a concentration of receivables due from gas and electric utilities and
their affiliates, as well as industrial customers throughout the United States.
These concentrations of customers may affect the Predecessor Companies' overall
credit risk in that certain customers may be similarly affected by changes in
economic, regulatory or other factors. Trade receivables are generally not
collateralized; however, the Predecessor Companies analyze customers' financial
condition prior to extending credit, establish credit limits and monitor the
appropriateness of these limits on an ongoing basis.

10. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of SFAS No. 107,
"Disclosures about Fair Value of Financial Instruments." The estimated fair
value amounts have been determined by the Predecessor Companies, using available
market information and appropriate valuation methodologies. However,
considerable judgment is necessarily required in interpreting market data to
develop the estimates of fair value. Accordingly, the estimates presented herein
are not necessarily indicative of the amounts that the Predecessor Companies
could realize in a current market exchange. The use of different market
assumptions and/or estimation methodologies may have a material effect on the
estimated fair value amounts.

<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
--------------------------- -------------------------
CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR
AMOUNT VALUE AMOUNT VALUE
---------- -------------- -------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents.............. $ 168 $ 168 $ 792 $ 792
Accounts receivable.................... 240,114 240,114 464,133 464,133
Notes receivable....................... 15,096 15,294 21,866 22,582
Accounts payable....................... 217,182 217,182 450,205 450,205
Advances, net -- parents............... 334,057 334,057 1,579,475 1,579,475
Notes payable.......................... 641,600 601,606 690,480 655,843
Natural gas, NGL and oil hedge
contracts............................ -- 1,800 -- (63,500)
</TABLE>

The fair value of cash and cash equivalents, accounts receivable, and
accounts payable are not materially different from their carrying amounts
because of the short-term nature of these instruments or the stated rates
approximating market rates.

F-24
<PAGE> 76
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

Notes receivable is carried in the accompanying balance sheet at cost. Fair
value has been estimated using discounted cash flows assuming current interest
rates, similar credit risk and maturities.

Related party advances and notes payable are carried at cost. Fair value
has been estimated using discounted cash flows of maturities of five years and
interest rates of 8.0%.

The estimated fair value of the natural gas, NGL and oil hedge contracts is
determined by multiplying the difference between the quoted termination prices
for natural gas, NGL and oil and the hedge contract prices by the quantities
under contract.

11. COMMITMENTS AND CONTINGENT LIABILITIES

The midstream natural gas industry has seen an increase in the number of
class action lawsuits involving royalty disputes, mismeasurement and mispayment
allegations. Although the industry has seen these types of cases before, they
were typically brought by a single plaintiff or small group of plaintiffs. Many
of these cases are now being brought as class actions. The Predecessor Companies
are currently named as defendants in certain of these cases. Management believes
the Predecessor Companies have meritorious defenses to these cases, and
therefore will continue to defend them vigorously. However, these class actions
can be costly and time consuming to defend.

The Predecessor Companies are subject to federal, state and local
regulations regarding air and water quality, hazardous and solid waste disposal
as well as other environmental matters. The Predecessor Companies are not aware
of any material violations and have accrued for the known remediation that is in
process. In connection with the UP Fuels acquisition, the Predecessor Companies
analyzed water and soil samples surrounding UP Fuels facilities and identified
necessary remedial actions. The Predecessor Companies transferred this
obligation to a third party for a payment of approximately $48 million.
Generally, environmental liabilities are not expected to be recoverable from
insurance or other third parties.

The Predecessor Companies utilize assets under operating leases in several
areas of operation. Combined rental expense amounted to $8.1 million, $8.2
million and $11.8 million in 1997, 1998 and 1999, respectively. Minimum rental
payments under the Predecessor Companies' various operating leases for the years
2000 through 2004 are $6.1, $6.0, $5.0, $5.0 and $4.3 million, respectively.
Thereafter, payments aggregate $15.4 million through 2011.

F-25
<PAGE> 77
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

12. STOCK-BASED COMPENSATION, PENSION AND OTHER BENEFITS

Under Duke Energy's 1999 Stock Incentive Plan, stock options of Duke
Energy's common stock may be granted to key employees of the Predecessor
Companies. Under the plan, the exercise price of each option granted equals the
market price of Duke Energy's common stock on the date of grant. Vesting periods
range from one to five years with a maximum exercise term of ten years. The
following tables set forth information regarding options to purchase Duke
Energy's common stock granted to employees of the Predecessor Companies.

Stock Option Activity

<TABLE>
<CAPTION>
WEIGHTED
OPTIONS AVERAGE
(IN THOUSANDS) EXERCISE PRICE
-------------- --------------
<S> <C> <C>
Outstanding at December 31, 1996............................ 254 $20
Granted................................................... 25 44
Exercised................................................. (54) 18
Forfeited................................................. -- --
----- ---
Outstanding at December 31, 1997............................ 225 23
Granted................................................... 279 55
Exercised................................................. (70) 21
Forfeited................................................. -- --
----- ---
Outstanding at December 31, 1998............................ 434 44
Granted................................................... 878 53
Exercised................................................. (33) 25
Forfeited................................................. (18) 55
----- ---
Outstanding at December 31, 1999............................ 1,261 51
</TABLE>

Stock Options at December 31, 1999

<TABLE>
<CAPTION>
OUTSTANDING EXERCISABLE
---------------------------------------- -------------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF AVERAGE AVERAGE AVERAGE
EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE
PRICES (IN THOUSANDS) LIFE (YEARS) PRICE (IN THOUSANDS) PRICE
-------- -------------- ------------ -------- -------------- --------
<S> <C> <C> <C> <C> <C>
$10 to $14 16 1.5 $11 16 $ 11
$15 to $20 52 3.9 18 52 18
$21 to $25 25 5.1 23 25 23
$26 to $31 10 6.1 27 10 27
$42 to $50 474 9.8 49 22 44
$55 to $60 684 8.8 56 66 55
----- ---
Total 1,261 191 34
</TABLE>

There were 29,646 and 82,050 options exercisable at December 31, 1997 and
1998 with a weighted average exercise price of $21 and $22 per option.

No compensation cost related to the stock options has been recorded as the
intrinsic method of accounting is used and the exercise price of each option
granted equaled the market price on the date of grant. The weighted average fair
value of options granted was $10.00, $9.00 and $10.00 per option during 1997,
1998 and 1999, respectively. The fair value of each option granted was estimated
on the date of grant using the Black-Scholes option-pricing model. The
weighted-average assumptions for option-pricing

F-26
<PAGE> 78
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

in 1997, 1998 and 1999 were: stock dividend yield of 3.5%, 4.2% and 4.1%,
expected stock price volatility of 20.7%, 15.1% and 18.8% and risk-free interest
rates of 6.5%, 5.6% and 5.9%, respectively. The expected option life for 1997,
1998 and 1999 was seven years. Stock-based compensation expense calculated using
the Black-Scholes option-pricing model for 1997, 1998 and 1999 would have been
$0.1 million, $0.8 million and $2.5 million, respectively and net income would
have been $51.1 million, $1.5 million and $41.8 million, respectively.

In addition, Duke Energy granted restricted shares of Duke Energy common
stock to key employees of the Predecessor Companies under Duke Energy stock
incentive plans. Grants under the plans vest over periods ranging from one to
seven years. In 1997 and 1999 Duke Energy awarded 2,817 shares (fair value at
grant dates of approximately $168,000) and 36,300 shares (fair value at grant
dates of approximately $2 million) to key employees of the Predecessor
Companies. No restricted shares were awarded in 1998. Compensation expense for
the stock grants is charged to the earnings of the Predecessor Companies over
the vesting period, and amounted to approximately $168,000, $0 and $488,000 in
1997, 1998 and 1999, respectively.

Duke Energy has, and the Predecessor Companies' participate in, a
non-contributory trustee pension plan which covers eligible employees with a
minimum of one year vesting service. The plan provides pension benefits for
eligible employees of the Predecessor Companies that are generally based on the
employee's actual eligible earnings and accrued interest. Through December 31,
1998, for certain eligible employees, a portion of their benefit may also be
based on the employee's years of benefit accrual service and highest average
eligible earnings. Effective January 1, 1999, the benefit formula under the plan
for all eligible employees was changed to a cash balance formula. Duke Energy's
policy is to fund amounts, as necessary, on an actuarial basis to provide assets
sufficient to meet benefits to be paid to plan members. Aspects of the plan
specific to the Predecessor Companies is as follows:

COMPONENTS OF NET PERIODIC PENSION COSTS

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1997 1998 1999
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost................................................ $ 950 $ 911 $ 1,280
Interest cost............................................... 681 794 1,375
Expected return on plan assets.............................. (1,227) (1,391) (2,307)
Amortization of transition (asset)/liability................ (86) (86) (85)
Amortization of prior service cost.......................... 29 43 34
Amortization of (gains)/losses.............................. 6
Settlement gain............................................. (40)
------- ------- -------
Net periodic pension cost................................... $ 347 $ 231 $ 303
======= ======= =======
</TABLE>

F-27
<PAGE> 79
DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES

NOTES TO COMBINED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED

RECONCILIATION OF FUNDED STATUS TO PRE-FUNDED PENSION COSTS

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1999
------- -------
(IN THOUSANDS)
<S> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year..................... $ 9,219 $14,651
Service cost................................................ 911 1,280
Interest cost............................................... 794 1,375
Intercompany transfers...................................... 802 8,519
Benefits paid............................................... (250) (190)
Actuarial (gains)/losses.................................... 3,261 (3,789)
Plan amendments............................................. (86)
------- -------
Benefit obligation at end of year........................... $14,651 $21,846
======= =======
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1999
------- -------
(IN THOUSANDS)
<S> <C> <C>
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year.............. $16,868 $20,211
Intercompany transfers...................................... 743 8,519
Actual return on plan assets................................ 2,580 4,985
Employer contributions...................................... 270 302
Benefits paid............................................... (250) (190)
------- -------
Fair value of plan assets at end of year.................... $20,211 $33,827
======= =======
Funded status............................................... $ 5,563 $11,982
Unrecognized net transition asset........................... (510) (425)
Unrecognized prior service cost............................. 302 268
Unrecognized gains.......................................... (794) (7,267)
------- -------
Pre-funded pension costs.................................... $ 4,561 $ 4,558
======= =======
</TABLE>

Intercompany transfers relate to benefit obligations and plan assets
associated with employees transferring between the Predecessor Companies and
other Duke Energy affiliates.

ASSUMPTIONS USED FOR PENSION BENEFIT ACCOUNTING

<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
--------------------
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
Discount rate............................................... 7.25% 6.75% 7.50%
Rate of increase in compensation levels..................... 4.75% 4.67% 4.50%
Expected long-term rate of return on plan assets............ 9.25% 9.25% 9.25%
</TABLE>

The Predecessor Companies also sponsor an employee savings plan which
covers substantially all employees. During 1997, 1998 and 1999, the Predecessor
Companies expensed plan contributions of $1.6 million, $1.8 million and $3.6
million, respectively.

The Predecessor Companies' postretirement benefits, in conjunction with
Duke Energy, consist of certain health care and life insurance benefits for
certain retired employees. Postretirement benefits costs were not material in
1997, 1998 and 1999.

F-28
<PAGE> 80

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1999 2000
------------ -----------
(UNAUDITED)
<S> <C> <C>
ASSETS

CURRENT ASSETS:
Cash and cash equivalents................................. $ 792 $ 2,593
Accounts receivable:
Customers, net......................................... 370,139 722,451
Affiliates............................................. 63,927 157,606
Other.................................................. 30,067 41,448
Inventories............................................... 38,701 52,566
Notes receivable.......................................... 13,050 6,502
Other..................................................... 1,580 3,111
---------- ----------
Total current assets.............................. 518,256 986,277
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 2,409,385 4,441,160
INVESTMENT IN AFFILIATES.................................... 343,835 276,443
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net.................. 102,382 101,970
Goodwill, net............................................. 85,846 84,735
OTHER NONCURRENT ASSETS..................................... 12,131 85,202
---------- ----------
TOTAL ASSETS...................................... $3,471,835 $5,975,787
========== ==========

LIABILITIES AND EQUITY

CURRENT LIABILITIES:
Accounts payable:
Trade.................................................. $ 353,977 $ 790,865
Affiliates............................................. 62,370 68,423
Other.................................................. 33,858 40,599
Short-term debt........................................... -- 2,585,290
Accrued taxes other than income........................... 15,653 17,693
Advances, net............................................. 1,579,475 80,879
Notes payable -- affiliates............................... 588,880 --
Other..................................................... 6,372 31,904
---------- ----------
Total current liabilities......................... 2,640,585 3,615,653
DEFERRED INCOME TAXES....................................... 308,308 --
NOTE PAYABLE TO PARENT...................................... 101,600 --
OTHER LONG TERM LIABILITIES................................. 34,871 38,923
COMMITMENTS AND CONTINGENT LIABILITIES
EQUITY:
Common stock.............................................. 1 --
Paid-in capital........................................... 213,091 --
Members' interest......................................... -- 1,695,108
Retained earnings......................................... 173,091 627,220
Other comprehensive income (loss)......................... 288 (1,117)
---------- ----------
Total equity...................................... 386,471 2,321,211
---------- ----------
TOTAL LIABILITIES AND EQUITY................................ $3,471,835 $5,975,787
========== ==========
</TABLE>

See Notes to Consolidated Financial Statements.

F-29
<PAGE> 81

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF INCOME
JUNE 30, 1999 AND 2000
(UNAUDITED)
(IN THOUSANDS)

<TABLE>
<CAPTION>
SIX MONTHS ENDED
-----------------------
JUNE 30, JUNE 30,
1999 2000
---------- ----------
<S> <C> <C>
OPERATING REVENUES:
Sales of natural gas and petroleum products............... $1,032,880 $3,542,823
Transportation, storage and processing.................... 75,964 80,748
---------- ----------
Total operating revenues.......................... 1,108,844 3,623,571
---------- ----------
COSTS AND EXPENSES:
Natural gas and petroleum products........................ 916,310 3,115,037
Operating and maintenance................................. 78,745 140,354
Depreciation and amortization............................. 56,006 105,359
General and administrative................................ 30,759 69,976
Net (gain) loss on sale of assets......................... (9) 337
---------- ----------
Total costs and expenses.......................... 1,081,811 3,431,063
---------- ----------
OPERATING INCOME............................................ 27,033 192,508
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES............. 10,275 14,707
---------- ----------
EARNINGS BEFORE INTEREST AND TAXES.......................... 37,308 207,215
INTEREST EXPENSE............................................ 25,535 59,851
---------- ----------
INCOME BEFORE INCOME TAXES.................................. 11,773 147,364
INCOME TAX EXPENSE (BENEFIT)................................ 5,618 (306,765)
---------- ----------
NET INCOME.................................................. $ 6,155 $ 454,129
========== ==========
</TABLE>

See Notes to Consolidated Financial Statements.

F-30
<PAGE> 82

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF EQUITY
SIX MONTHS ENDED JUNE 30, 2000
(UNAUDITED)
(IN THOUSANDS)

<TABLE>
<CAPTION>
OTHER
ADDITIONAL COMPREHENSIVE
COMMON PAID-IN MEMBERS' RETAINED INCOME
STOCK CAPITAL INTEREST EARNINGS (LOSS) TOTAL
------ ---------- ----------- -------- ------------- -----------
<S> <C> <C> <C> <C> <C> <C>
Balance, January 1, 2000............. $ 1 $ 213,091 $ -- $173,091 $ 288 $ 386,471
Combination at March 31,
2000 -- see Note 2:
Contribution of TEPPCO general
partnership interest........... 1,443 1,443
Contribution of DEFS Inc. and
DEFSCL to DEFS, LLC............ (1) (214,534) 214,535 --
Contribution of notes and
advances payable............... 2,305,092 2,305,092
Contribution of GPM assets and
liabilities.................... 1,919,800 1,919,800
Distributions.................... (2,744,319) (2,744,319)
Net income......................... 454,129 454,129
Other.............................. (1,405) (1,405)
--- --------- ----------- -------- ------- -----------
Balance, June 30, 2000............... $-- $ -- $ 1,695,108 $627,220 $(1,117) $ 2,321,211
=== ========= =========== ======== ======= ===========
</TABLE>

See Notes to Consolidated Financial Statements.

F-31
<PAGE> 83

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
JUNE 30, 1999 AND 2000
(UNAUDITED)
(IN THOUSANDS)

<TABLE>
<CAPTION>
SIX MONTHS ENDED
--------------------------
JUNE 30, JUNE 30,
1999 2000
----------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 6,155 $ 454,129
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization.......................... 56,006 105,359
Deferred income tax expense (benefit).................. 24,311 (308,230)
Equity in earnings of unconsolidated affiliates........ (10,275) (14,707)
Loss (gain) on sale of assets.......................... (9) 337
Net change in operating assets and liabilities:
Accounts receivable.................................... (2,980) (236,018)
Inventories............................................ 1,556 (39,532)
Other current assets................................... (1,482) 43,583
Other non-current assets............................... 3,774 (2,232)
Accounts payable....................................... 64,729 343,424
Other current liabilities.............................. (8,612) (7,155)
Other long term liabilities............................ (2,018) (14,215)
----------- -----------
Net cash provided by operating activities......... 131,155 324,743
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions and other capital expenditures............... (1,519,053) (214,269)
Investment expenditures................................... (34,187) (1,327)
Investment distributions.................................. 9,939 12,093
Proceeds from sales of assets............................. 225 14,220
----------- -----------
Net cash used in investment activities............ (1,543,076) (189,283)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in advances -- parents............ 1,369,761 25,370
Distributions............................................. -- (2,744,319)
Proceeds from issuing debt................................ 47,857 2,790,900
Payment of debt........................................... (5,488) (205,610)
----------- -----------
Net cash flows provided by (used in) financing
activities..................................... 1,412,130 (133,659)
NET INCREASE IN CASH AND CASH EQUIVALENTS:.................. 209 1,801
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.............. 168 792
----------- -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................... $ 377 $ 2,593
=========== ===========
</TABLE>

See Notes to Consolidated Financial Statements.

F-32
<PAGE> 84

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)

1. GENERAL

Duke Energy Field Services, LLC (with its consolidated subsidiaries, the
Company or Field Services LLC) operates in the midstream natural gas gathering,
marketing and natural gas liquids industries. The Company operates in the two
principal segments of the midstream natural gas industry of (1) natural gas
gathering, processing, transportation, marketing and storage; and (2) natural
gas liquids (NGLs) fractionation, transportation, marketing and trading.

Effective March 31, 2000, and in connection with the Combination (see Note
2), Duke Energy Field Services, Inc. (DEFS Inc.) was converted to a limited
liability company, and was contributed by Duke Energy Corporation (Duke Energy)
to the Company as a wholly-owned subsidiary. Also on March 31, 2000, Duke Energy
contributed Duke Energy Field Services Canada, Ltd. (DEFSCL) to Field Services
LLC. As a result of these contributions to the Company, the June 30, 2000
financial statements are reflected as consolidated.

The interim consolidated financial statements presented herein should be
read in conjunction with the 1999 combined financial statements and notes
thereto of Duke Energy Field Services, LLC and Affiliates. In the opinion of
management, all adjustments necessary for a fair presentation of the results for
the unaudited interim periods have been made. Except as explicitly noted, these
adjustments consist solely of normal recurring accruals.

2. COMBINATION

On March 31, 2000, the natural gas gathering, processing and natural gas
liquid assets, operations, and subsidiaries of Duke Energy were contributed to
Field Services LLC. In connection with the contribution of assets and
subsidiaries at March 31, 2000, notes and advances payable to Duke Energy were
eliminated and contributed to equity. Also on March 31, 2000, Phillips Petroleum
Company (Phillips) contributed its midstream natural gas gathering, processing
and natural gas liquid operations to Field Services LLC. This contribution and
Duke Energy's contribution to Field Services LLC are referred to as the
"Combination." In connection with the Combination, the Company made one-time
distributions to Phillips of $1,219.8 million and to Duke Energy of $1,524.5
million. In exchange for the contributions, and after the one-time
distributions, Duke Energy received a 69.7% member interest in Field Services
LLC, with Phillips holding the remaining 30.3% member interest.

The Combination has been accounted for as a purchase business combination
in accordance with Accounting Principles Board Opinion (APB) No. 16 "Accounting
for Business Combinations". The Phillips assets, net of liabilities, have been
valued at $1,919.8 million. Following is a summary of the preliminary allocation
of purchase price (in millions):

<TABLE>
<S> <C>
Property, plant and equipment............................... $1,878.4
Other assets, net........................................... 41.4
--------
Total purchase price.............................. $1,919.8
========
</TABLE>

The purchase price has not yet been fully allocated to the individual
assets and liabilities acquired. The final allocation will be determined based
on independent appraisals.

Working Capital Adjustments -- In connection with the Combination, Duke
Energy and Phillips each were to make contributions to Field Services LLC, or
receive distributions from Field Services LLC so that each of Duke Energy and
Phillips would have contributed to Field Services LLC net working capital
positions equal to zero as of March 31, 2000. As of June 30, 2000, Field
Services LLC had advances

F-33
<PAGE> 85
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

payable to Duke Energy and Phillips of $80.9 million representing distributions
payable to net the working capital positions as of March 31, 2000.

Pro Forma Disclosures -- Revenues for the six months ended June 30, 1999
and 2000, on a pro forma basis would have increased $618.0 million and $542.4
million, respectively, and net income for the six months ended June 30, 1999 and
2000, on a pro forma basis would have decreased by $15.6 million and increased
by $65.7 million, respectively, if the acquisition of the Phillips midstream
business had occurred at the beginning of the period presented.

TEPPCO General Partner Interest -- On March 31, 2000, and in connection
with the Combination, Duke Energy contributed the general partner interest of
TEPPCO Partners L.P. to Field Services LLC. In connection with the contribution
of the general partner interest in TEPPCO, the Company recorded an investment in
TEPPCO of $1.4 million and increased stockholders' equity by $1.4 million.

TEPPCO is a publicly traded limited partnership that owns and operates a
network of pipelines for refined products and crude oil. The general partner is
responsible for the management and operations of TEPPCO. Through the ownership
of the general partner of TEPPCO, Field Services LLC has the right to receive
from TEPPCO incentive cash distributions in addition to a 2% share of
distributions based on the general partner interest. At TEPPCO's 1999 per unit
distribution level, the general partner received approximately 14% of the cash
distributed by TEPPCO to its partners. Due to the general partner's share of
unit distributions and control exercised through its management of the
partnership, the Company's investment in TEPPCO is accounted for under the
equity method.

3. INCOME TAXES

At March 31, 2000 the Company converted to the limited liability company
which is a pass-through entity for income tax purposes. As a result,
substantially all of the existing net deferred tax liability ($327 million) was
eliminated with a corresponding income tax benefit recorded.

4. ACQUISITIONS

Union Pacific Fuels, Inc. -- On March 31, 1999, the Company acquired the
assets and assumed certain liabilities of Union Pacific Fuels, Inc. (UP Fuels),
a wholly-owned subsidiary of Union Pacific Resources Corporation, for a total
purchase price of $1,359 million. The acquisition was accounted for under the
purchase method of accounting, and the assets and liabilities and results of
operations of UP Fuels have been consolidated in the Company's financial
statements since the date of purchase. Revenues and net income for the six
months ended June 30, 1999 on a pro forma basis would have increased $298
million and $3.4 million respectively, if the acquisition of UP Fuels had
occurred on January 1, 1999.

Conoco and Mitchell Assets -- On March 31, 2000, Field Services LLC
acquired gathering and processing facilities located in central Oklahoma from
Conoco, Inc. and Mitchell Energy & Development Corp. Field Services LLC paid
cash of $99.5 million, and exchanged its interests in certain gathering and
marketing joint ventures located in southeast Texas having a total fair value of
$42.0 million as consideration for these facilities. A $3.9 million gain was
recorded in connection with the exchange.

5. AGREEMENTS AND TRANSACTIONS WITH DUKE ENERGY

Services Agreement with Duke Energy -- Effective with the Combination, the
Company entered into a services agreement with Duke Energy ("the Duke Energy
Services Agreement"). Under the Duke Energy Services Agreement, Duke Energy will
provide the Company with various staff and support services, including
information technology products and services, payroll, employee benefits,
corporate insurance, cash management, ad valorem taxes, treasury and legal
functions and shareholder services. These services
F-34
<PAGE> 86
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

will be priced on the basis of a monthly charge approximating market prices. The
Duke Energy Services Agreement expires on December 31, 2000.

Transactions between Duke Energy and the Company -- Through June 30, 2000,
the Company has conducted a series of transactions with Duke Energy in which the
Company has sold a portion of its residue gas and NGLs to, purchased raw natural
gas and other petroleum products from, and provided gathering and transportation
services over its gathering systems and pipelines to, Duke Energy and its
subsidiaries at contractual prices that have approximated market prices in the
ordinary course of the Company's business. The Company anticipates continuing
these transactions in the ordinary course of business.

6. AGREEMENTS AND TRANSACTIONS WITH PHILLIPS

Services Agreement with Phillips -- Effective with the Combination, the
Company entered into a services agreement with Phillips ("the Phillips Services
Agreement"). Under the Phillips Services Agreement, Phillips will provide the
Company with various staff and support services, including information
technology products and services, cash management, real estate and property tax
services. These services will be priced on a basis of a monthly charge equal to
Phillips' fully-burdened cost of providing the services. The Phillips Services
Agreement expires on December 31, 2000.

Long-Term NGLs Purchases Contract with Phillips -- In connection with the
Combination, the Company has agreed to maintain the NGL Output Purchase and Sale
Agreement ("Phillips NGL Agreement") between Phillips and the midstream natural
gas assets that were contributed by Phillips to the Company in the Combination.
Under the Phillips NGL Agreement, Phillips 66 Company, a wholly-owned subsidiary
of Phillips, has the right to purchase at index-based prices substantially all
NGLs produced by the processing plants which were acquired by Field Services LLC
from Phillips in the Combination. The Phillips NGL Agreement also grants
Phillips 66 Company the right to purchase at index-based prices certain
quantities of NGLs produced at processing plants that are acquired and/or
constructed by the Company in the future in various counties in the
Mid-Continent and Permian Basis regions, and the Austin Chalk area. The primary
term of the agreement is effective until December 31, 2014.

Transactions between Phillips and the Midstream Business Acquired from
Phillips -- Through June 30, 2000, the Phillips' businesses (the "Phillips
Combined Subsidiaries") that owned the midstream natural gas assets that were
contributed to the Company in the Combination had conducted a series of
transactions with Phillips in which the Phillips Combined Subsidiaries sold a
portion of their residue gas and other by-products to Phillips at contractual
prices that approximated market prices. In addition, Phillips Combined
Subsidiaries purchased raw natural gas from Phillips at contractual prices that
have approximated market prices. The Company anticipates continuing these
transactions in the ordinary course of business.

7. FINANCING

Credit Facility with Financial Institutions -- In March 2000, Field
Services LLC entered into a $2,800 million credit facility with several
financial institutions. The credit facility will be used to support a commercial
paper program for short-term financing requirements. In April, 2000, Field
Services LLC borrowed $2,790.9 million in the commercial paper market to fund
one-time cash distributions of $1,524.5 million to Duke Energy, and $1,219.8
million to Phillips, and to meet working capital requirements. The credit
facility matures on March 30, 2001, and bears interest at a rate equal to, at
Field Services LLC's option, either (1) the London Interbank Offered Rate
(LIBOR) plus .50% per year for the first 90 days following March 31, 2000 and
LIBOR plus .625% per year thereafter, or (2) the higher of (a) the Bank of
America prime rate and (b) the Federal Funds rate plus .50% per year.

F-35
<PAGE> 87
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

8. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Historically, the Company's commodity price risk management program had
been directed by Duke Energy under its centralized program for controlling,
managing and coordinating its management of risks. During the six months ended
June 30, 1999, and the three months ended March 31, 2000, the Company recorded a
hedging gain of $4.4 million and a hedging loss of $46.7 million under Duke
Energy's centralized program. As of March 31, 2000, the commodity positions then
held under the Duke Energy centralized program were transferred to Duke Energy.

Effective April 1, 2000, the Company began directing its risk management
activities, including commodity price risk for market fluctuations in the price
of NGLs, independently of Duke Energy. The Company plans to use commodity-based
derivative contracts to reduce the risk in the Company's overall earnings and
cash flow with the primary goals of: (1) maintaining minimum cash flow to fund
debt service, dividends and maintenance type capital projects; (2) avoiding
disruption of the Company's growth capital and value creation process; and (3)
retaining a high percentage of the potential upside relation to commodity price
increases. The Company has implemented a risk management policy that provides
guidelines for entering into contractual arrangements to manage commodity price
exposure. Futures and swaps will be used to manage and hedge prices related to
these market exposures. During the three months ended June 30, 2000, the Company
recorded a hedging loss of $12.5 million under the Company's self-directed risk
management program.

In establishing its initial independent commodity risk management position,
on April 1, 2000 the Company acquired a portion of Duke Energy's existing
commodity derivatives held for non trading purposes. The absolute notional
contract quantity of the positions acquired was 4,607,000 barrels of crude oil.
Such positions were acquired at market value.

Interest Rate Derivatives -- In the second quarter of 2000, the Company
issued derivatives that reduce the Company's exposure to market fluctuations in
the interest rates that will be included in the proposed public offering of debt
securities to be sold in the third quarter of 2000. The Company's interest rate
market exposure arises from changes in the effective interest rates at the
inception of long-term financing between the date that the Company has decided
to sell debt securities and the date the debt securities are actually sold.
Locks and swaps are used to manage and hedge interest rates related to these
market exposures.

The gains, losses, and costs related to these interest rate derivatives
that qualify as a hedge will not be recognized until debt securities are
actually sold, and then will be recognized over the estimated life of the debt
securities. At June 30, 2000, the Company's net realized and unrealized losses
related to the interest rate hedges was $1.9 million. At June 30, 2000, the
absolute notional contract quantity of interest rate derivatives held for
hedging purposes for the effective interest rates at the inception of long-term
financing was $1,150.0 million.

9. COMMITMENTS AND CONTINGENT LIABILITIES

The midstream natural gas industry has seen an increase in the number of
class action lawsuits involving royalty disputes, mismeasurement and mispayment
allegations. Although the industry has seen these types of cases before, they
were typically brought by a single plaintiff or small group of plaintiffs. Many
of these cases are now being brought as class actions. The Company and its
subsidiaries are currently named as defendants in certain of these cases.
Management believes the Company and its subsidiaries have meritorious defenses
to these cases, and therefore will continue to defend them vigorously. However,
these class actions can be costly and time consuming to defend.

F-36
<PAGE> 88
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

A judgment has been entered in the case of Chevron U.S.A., Inc. versus GPM
Gas Corporation (GPM), a wholly owned subsidiary of Field Services LLC,
upholding and construing most favored nations clauses in three 1961 West Texas
gas purchase contracts. Although a federal district court decided that GPM owes
Chevron damages in the amount of $13,828,030 through July 31, 1998, plus 6
percent interest from that date and attorneys' fees in the amount of $329,994.
GPM has appealed the judgment to the U.S. Court of Appeals for the Fifth
Circuit.

10. STOCK-BASED COMPENSATION, PENSION AND OTHER BENEFITS

Effective March 31, 2000, participation by the Company's employees in Duke
Energy's non-contributory trustee pension plan and employee savings plan were
terminated. Effective April 1, 2000, the Company's employees began participation
in the Company's employee savings plan, in which the Company contributes 4% of
each eligible employee's qualified wages. Additionally, the Company matches
employees' contributions to the plan up to 6% of qualified wages.

In June 2000, the Company granted approximately 37,000 restricted shares of
Duke Energy common stock to key employees of the Company under Duke Energy's
stock incentive plans. These restricted shares vest over periods ranging from
two to three years. Under the grant terms of the restricted shares, when the
Company completes its initial public stock offering, these restricted shares in
Duke Energy common stock will be converted to restricted shares of the Company's
common stock under a formula that equates the value of the Company's common
shares at the initial public offering to the value of the Duke Energy restricted
common shares at the grant date.

Also in June 2000, the Company granted approximately 105,000 stock options
of Duke Energy's common stock under Duke Energy's 1999 Stock Incentive Plan. The
exercise price for these stock options is $59. Under the grant terms of the
stock options, when the Company completes its initial public stock offering,
these stock options in Duke Energy common stock will be converted to stock
options of the Company's common stock under a formula that equates the value of
the Company's stock options at the initial public offering to the value of the
Duke Energy stock options at the grant date.

11. BUSINESS SEGMENTS

The Company operates in two principal business segments as follows: (1)
natural gas gathering, processing, transportation, marketing and storage, and
(2) natural gas liquids fractionation, transportation, marketing and trading.
These segments are monitored separately by management for performance against
its internal forecast and are consistent with the Company's internal financial
reporting. These segments have been identified based on the differing products
and services, regulatory environment and the expertise required for these
operations. Margin, earnings before interest, taxes, depreciation and
amortization (EBITDA) and earnings before interest and taxes (EBIT) are the
performance measures utilized by management to monitor the business of each
segment. The accounting policies for the segments are the same as those
described in Note 1. Foreign operations are not material and are therefore not
separately identified.

F-37
<PAGE> 89
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The following table sets forth the Company's segment information for the
six months ended June 30, 1999 and 2000 and as of December 31, 1999 and June 30,
2000.

<TABLE>
<CAPTION>
FOR THE SIX MONTH PERIODS
ENDED
-------------------------------
JUNE 30, JUNE 30,
1999 2000
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Operating revenues:
Natural gas............................................... $ 847,782 $2,585,992
NGLs...................................................... 396,042 1,607,882
Intersegment(a)........................................... (134,980) (570,303)
---------- ----------
Total operating revenues.......................... 1,108,844 3,623,571
---------- ----------
Margin:
Natural gas............................................... 184,365 482,066
NGLs...................................................... 8,169 26,468
---------- ----------
Total margin...................................... 192,534 508,534
---------- ----------
Other operating costs:
Natural gas............................................... 78,176 139,516
NGLs...................................................... 560 1,175
Corporate................................................. 30,759 69,976
---------- ----------
Total other operating costs....................... 109,495 210,667
---------- ----------
Equity in earnings of unconsolidated affiliates:
Natural Gas............................................... 10,275 13,888
NGLs...................................................... 819
---------- ----------
Total equity in earnings of unconsolidated
affiliates...................................... 10,275 14,707
---------- ----------
EBITDA(b):
Natural gas............................................... 116,464 356,438
NGLs...................................................... 7,609 26,112
Corporate................................................. (30,759) (69,976)
---------- ----------
Total EBITDA...................................... 93,314 312,574
---------- ----------
Depreciation and amortization:
Natural gas............................................... 53,612 97,667
NGLs...................................................... 1,249 6,112
Corporate................................................. 1,145 1,580
---------- ----------
Total depreciation and amortization............... 56,006 105,359
---------- ----------
EBIT:
Natural gas............................................... 62,852 258,771
NGLs...................................................... 6,360 20,000
Corporate................................................. (31,904) (71,556)
---------- ----------
Total EBIT........................................ 37,308 207,215
---------- ----------

Corporate interest expense.................................. 25,535 59,851
</TABLE>

F-38
<PAGE> 90
DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE SIX MONTH PERIODS
ENDED
-------------------------------
JUNE 30, JUNE 30,
1999 2000
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
---------- ----------
Income before income taxes:
Natural gas............................................... 62,852 258,771
NGLs...................................................... 6,360 20,000
Corporate................................................. (57,439) (131,407)
---------- ----------
Total income before income taxes.................. $ 11,773 $ 147,364
========== ==========
</TABLE>

<TABLE>
<CAPTION>
AS OF
------------------------------
DECEMBER 31, JUNE 30,
1999 2000
-------------- -------------
(IN THOUSANDS)
<S> <C> <C>
Total assets:
Natural gas............................................... $2,754,447 $4,833,083
NGLs...................................................... 225,702 197,624
Corporate(c).............................................. 491,686 945,080
---------- ----------
Total assets...................................... $$3,471,835 $5,975,787
========== ==========
</TABLE>

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

F-39
<PAGE> 91

REPORT OF INDEPENDENT AUDITORS

The Board of Directors and Stockholder
Phillips Gas Company

We have audited the accompanying consolidated balance sheets of Phillips
Gas Company as of December 31, 1998 and 1999, and the related consolidated
statements of income, changes in stockholders' equity (deficit) and cash flows
for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Phillips Gas
Company at December 31, 1998 and 1999, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.

ERNST & YOUNG LLP

Tulsa, Oklahoma
March 6, 2000

F-40
<PAGE> 92

PHILLIPS GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

<TABLE>
<CAPTION>
AT DECEMBER 31,
-----------------------
1998 1999
---------- ----------
<S> <C> <C>
ASSETS

Cash and cash equivalents................................... $ 27,045 $ 164,078
Accounts receivable
Affiliate................................................. 51,415 104,159
Trade (less allowances: 1998 -- $648; 1999 -- $329)....... 93,764 104,555
Inventories................................................. 4,957 3,066
Deferred income taxes....................................... 2,160 30,293
Prepaid expenses and other current assets................... 2,916 3,407
---------- ----------
Total Current Assets.............................. 182,257 409,558
Investments and long-term receivables....................... 13,013 9,585
Properties, plants and equipment (net)...................... 943,302 995,406
Deferred gathering fees..................................... 43,531 50,662
---------- ----------
Total............................................. $1,182,103 $1,465,211
========== ==========

LIABILITIES

Accounts payable
Affiliate................................................. $ 23,946 $ 106,410
Trade..................................................... 139,729 178,891
Deferred purchase obligation due within one year............ -- 8,300
Accrued income and other taxes.............................. 8,363 12,140
Other accruals.............................................. 212 63
---------- ----------
Total Current Liabilities......................... 172,250 305,804
Long-term debt due to affiliate............................. 560,000 1,350,000
Other liabilities and deferred credits...................... 4,908 3,065
Deferred income taxes....................................... 68,160 128,907
Deferred gain on sale of assets............................. 16,237 15,154
---------- ----------
Total Liabilities................................. 821,555 1,802,930
---------- ----------
STOCKHOLDER'S EQUITY/(DEFICIT)
Common stock -- 1,000 shares authorized at $.01 par value;
issued and outstanding -- 1,000 shares
Par value................................................. -- --
Capital in excess of par.................................. 142,917 --
Retained earnings/(accumulated deficit)..................... 217,631 (337,719)
---------- ----------
Total Stockholder's Equity/(Deficit).............. 360,548 (337,719)
---------- ----------
Total............................................. $1,182,103 $1,465,211
========== ==========
</TABLE>

See Notes to Financial Statements.

F-41
<PAGE> 93

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
REVENUES
Natural gas liquids...................................... $ 711,785 $ 514,758 $ 714,439
Residue gas.............................................. 923,376 722,931 786,739
Other.................................................... 80,994 68,919 90,234
---------- ---------- ----------
Total Revenues................................. 1,716,155 1,306,608 1,591,412
---------- ---------- ----------
COSTS AND EXPENSES
Gas purchases............................................ 1,268,570 940,464 1,148,910
Operating expenses....................................... 190,385 186,572 176,864
Selling, general and administrative expenses............. 14,990 13,290 15,560
Depreciation............................................. 76,737 77,240 80,458
Interest expense......................................... 20,468 36,194 35,643
---------- ---------- ----------
Total Costs and Expenses....................... 1,571,150 1,253,760 1,457,435
---------- ---------- ----------
Income before income taxes............................... 145,005 52,848 133,977
Provision for income taxes............................... 54,998 21,535 52,244
---------- ---------- ----------
NET INCOME............................................... 90,007 31,313 81,733
Preferred stock dividend requirements.................... 30,813 -- --
---------- ---------- ----------
NET INCOME APPLICABLE TO COMMON STOCK.................... $ 59,194 $ 31,313 $ 81,733
========== ========== ==========
</TABLE>

See Notes to Financial Statements.

F-42
<PAGE> 94

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................ $ 90,007 $ 31,313 $ 81,733
Adjustments to reconcile net income to net cash provided
by operating activities
Non-working capital adjustments
Depreciation......................................... 76,737 77,240 80,458
Deferred taxes....................................... 38,700 41,550 60,747
Deferred gathering fees.............................. (7,803) (7,231) (7,131)
Gain on sale of assets............................... (1,965) (9,848) (907)
Other................................................ (2,119) (6,795) 644
Working capital adjustments
Decrease (increase) in accounts receivable........... 70,180 27,847 (63,465)
Decrease (increase) in inventories................... (798) 2,259 1,891
Decrease (increase) in prepaid expenses and other
current assets, including deferred taxes........... (1,654) 3,084 (28,624)
Increase (decrease) in accounts payable.............. (30,027) (98,776) 121,626
Increase (decrease) in taxes and other accruals...... (12,712) (6,191) 3,628
--------- --------- ---------
Net Cash Provided by Operating Activities................. 218,546 54,452 250,600
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and investments...................... (116,520) (83,152) (124,009)
Proceeds from asset dispositions.......................... 5,499 17,611 442
--------- --------- ---------
Net Cash Used for Investing Activities.................... (111,021) (65,541) (123,567)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred stock dividends................................. (34,922) -- --
Redemption of preferred stock............................. (345,000) -- --
Issuance of debt.......................................... 345,000 -- 10,000
Repayment of debt......................................... -- (95,000) --
Payment of note payable................................... (18,500) -- --
--------- --------- ---------
Net Cash Provided by (Used for) Financing Activities...... (53,422) (95,000) 10,000
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...... 54,103 (106,089) 137,033
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR.............. 79,031 133,134 27,045
--------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR.................... $ 133,134 $ 27,045 $ 164,078
========= ========= =========
</TABLE>

See Notes to Financial Statements.

F-43
<PAGE> 95

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY/(DEFICIT)
(IN THOUSANDS)

<TABLE>
<CAPTION>
SHARES COMMON STOCK RETAINED
-------------------- --------------------- EARNINGS/
PREFERRED COMMON PREFERRED PAR CAPITAL IN (ACCUMULATED
STOCK STOCK STOCK VALUE EXCESS OF PAR DEFICIT)
----------- ------ --------- ----- ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
December 31, 1996............ 13,800,000 1,000 $ 345,000 -- $ 142,917 $ 131,233
Net income................... 90,007
Cash dividends paid on
preferred stock............ (34,922)
Redemption of preferred
stock...................... (13,800,000) (345,000)
----------- ----- --------- -- --------- ---------
December 31, 1997............ -- 1,000 -- -- 142,917 186,318
Net income................... 31,313
----------- ----- --------- -- --------- ---------
December 31, 1998............ -- 1,000 -- -- 142,917 217,631
Net income................... 81,733
Dividend declared............ (142,917) (637,083)
----------- ----- --------- -- --------- ---------
December 31, 1999............ -- 1,000 $ -- -- $ -- $(337,719)
=========== ===== ========= == ========= =========
</TABLE>

See Notes to Financial Statements.

F-44
<PAGE> 96

PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES

Consolidation Principles and Basis of Presentation -- Phillips Gas Company
(PGC or the company) is a subsidiary of Phillips Petroleum Company (Phillips).
Phillips owns 100 percent of the company's outstanding common stock.
Majority-owned, controlled subsidiaries are consolidated. Investments in
affiliates in which the company owns 20 percent to 50 percent of voting control
are accounted for using the equity method.

Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires Management to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and the disclosures of contingent assets and
liabilities. Actual results could differ from the estimates and assumptions
used.

Cash and Cash Equivalents -- Cash and cash equivalents are held by Phillips
as part of its centralized cash management system. Interest is paid monthly
based on the average daily balance of funds invested at a rate equal to the
weighted-average rate earned by Phillips or at the applicable federal funds
rate.

Cash equivalents are highly liquid short-term investments that are readily
convertible to known amounts of cash and have original maturities within three
months from their date of purchase.

Inventories -- Helium inventory is valued at cost, which is lower than
market, mainly on the last-in, first-out (LIFO) basis. Materials and supplies
are valued at, or below, average cost.

Derivative Contracts -- The company uses commodity swap and option
contracts. Commodity option contracts are recorded at market value through
monthly adjustments for unrealized gains and losses; however, swaps are not
marked to market. Gains and losses are recognized during the same period in
which the gains and losses from the underlying exposures being hedged are
recognized. In 1998 and 1999, the net realized and unrealized gains and losses
from derivative contracts were not material to the company's financial
statements.

Revenue Recognition -- Revenues associated with sales of natural gas,
natural gas liquids, and all other items are recorded when title passes to the
customer upon delivery.

Gas Exchanges and Imbalances -- Quantities of gas over-delivered or
under-delivered related to exchange or imbalance agreements are recorded monthly
as receivables or payables using the index price or the average price of gas at
the plant or system. Generally, these balances are settled with deliveries of
gas.

Depreciation -- Depreciation of plants and systems is determined using the
group composite straight-line method over an estimated life of 20 years for most
of the assets. Plants and systems are grouped for this purpose based on their
relative similarity and the degree of physical and economic interdependence
between individual pieces of equipment. Other relatively insignificant
properties and equipment are depreciated using the straight-line method over the
estimated useful lives of the individual assets.

Impairment of Assets -- Long-lived assets used in operations are assessed
for impairment whenever changes in facts and circumstances indicate a possible
significant deterioration in the future cash flows expected to be generated by
an asset group. If, upon review, the sum of the undiscounted pretax cash flows
are less than the carrying value of the asset group, the carrying value is
written down to estimated fair value.

The expected future cash flows used for impairment reviews and related fair
value calculations are based on the production volumes, prices and costs
considering all available evidence at the date of the review.

F-45
<PAGE> 97
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

Property Dispositions -- When complete units of depreciable property are
retired or sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in income. When less than complete
units of depreciable property are disposed of or retired, the difference between
asset cost and salvage value is charged or credited to accumulated depreciation
with no recognition of gain or loss. Retirements or sales of equipment, whether
complete units of depreciable property or less than complete units of
depreciable property, have been infrequent and not significant to the financial
statements.

Environmental Costs -- Environmental expenditures are expensed or
capitalized as appropriate, depending upon their future economic benefit.
Expenditures that relate to an existing condition caused by past operations, and
that do not have future economic benefit, are expensed. Liabilities for these
expenditures are recorded on an undiscounted basis when environmental
assessments or clean-ups are probable and the costs can be reasonably estimated.

Income Taxes -- Deferred taxes are computed using the liability method and
provided on all temporary differences between the financial reporting basis and
the tax basis of the assets and liabilities. Allowable tax credits are applied
currently as reductions of the provision for income taxes. The company's results
of operations for 1998 and 1999 were included in the consolidated federal income
tax return of Phillips, with any resulting tax liability or refund settled with
Phillips on a current basis. Income tax expense represents amounts due Phillips
for federal income taxes as if the company were filing a separate return, except
that the same principles and elections used in the consolidated return were
applied. Results of operations for 1997 were included in the separate federal
income tax return of Phillips Gas Company.

Income Per Share of Common Stock -- Income per share of common stock has
been omitted from the consolidated statement of income because all common stock
is owned by Phillips.

Comprehensive Income -- The company does not have any items of other
comprehensive income, as defined in Financial Accounting Standards Board (FASB)
Statement No. 130, "Reporting Comprehensive Income."

2. THE COMPANY'S BUSINESS

The company owns and operates natural gas gathering systems and processing
facilities concentrated in four major gas-producing areas in the Southwest. The
company's core gathering and processing regions are concentrated in the Permian
Basin area of West Texas and southeastern New Mexico, the Panhandle areas of
Texas and Oklahoma, and central and western Oklahoma. Under FASB Statement No.
131, "Disclosures about Segments of an Enterprise and Related Information," the
four regions have been aggregated into a single segment for financial reporting
purposes. At December 31, 1999, the company wholly owned 15 natural gas liquids
extraction plants, and had an interest in another. The plants are located in
Texas (9), Oklahoma (3), and New Mexico (4). During 1999, the company purchased
a co-venturer's interest in the Artesia plant and gathering system in New Mexico
that the company had operated under a construction and operating agreement since
1959.

The company sells substantially all of its natural gas liquids to Phillips.
The company is able to interconnect to major gas transmission pipelines in each
of its regions in order to sell residue gas to local distribution companies,
electric utilities, various other business and industrial users and marketers.
The company's major residue gas markets are located primarily in Texas, Oklahoma
and the midwestern United States.

F-46
<PAGE> 98
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

3. INVENTORIES

Inventories at December 31 consisted of the following:

<TABLE>
<CAPTION>
1998 1999
------ ------
(IN THOUSANDS)
<S> <C> <C>
Helium...................................................... $1,027 $ --
Materials, supplies and other............................... 3,930 3,066
------ ------
$4,957 $3,066
====== ======
</TABLE>

The company's helium inventory was sold in March 1999 for $4,989,000,
resulting in after-tax income of $2,575,000.

4. INVESTMENTS AND LONG-TERM RECEIVABLES

Components of investments and long-term receivables at December 31 were as
follows:

<TABLE>
<CAPTION>
1998 1999
------- ------
(IN THOUSANDS)
<S> <C> <C>
Investment in affiliated company............................ $ 3,328 $3,421
Long-term receivables....................................... 9,685 6,164
------- ------
$13,013 $9,585
======= ======
</TABLE>

In 1993 the company formed GPM Gas Gathering L.L.C. (GGG), a limited
liability company in which PGC invested approximately $4 million in exchange for
a 50 percent equity interest. In December 1993, the company sold a portion of
its gas gathering assets in the West Texas region of the Permian Basin to GGG
for $138 million. GGG is providing gas gathering services to the company under a
twenty-year contract. This contract does not represent a take-or-pay or
unconditional purchase obligation. Because of the company's continuing
involvement in GGG, a $22 million gain from the sale of the assets was deferred
and is being recognized over the economic life of the gathering assets. The
deferred gain recognized during 1998 and 1999 was $1,082,000 and $1,083,000,
respectively. Distributions received from GGG during 1998 and 1999 were
$1,153,000 and $955,000 respectively. See Note 10 for the gathering fees paid by
the company to GGG under this contract.

5. PROPERTIES, PLANTS AND EQUIPMENT

Properties, plants and equipment (net) at December 31 included the
following:

<TABLE>
<CAPTION>
USEFUL LIFE 1998 1999
----------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Gathering.................................... 15-20 Years $1,529,026 $1,657,605
Processing................................... 15-20 Years 561,170 591,127
Work in progress............................. 42,694 6,484
Other........................................ 3-5 Years 10,670 11,788
---------- ----------
Total property, plant & equipment (at
cost)...................................... 2,143,560 2,267,004
Less accumulated depreciation and
amortization............................... 1,200,258 1,271,598
---------- ----------
$ 943,302 $ 995,406
========== ==========
</TABLE>

F-47
<PAGE> 99
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

6. DEBT

Long-term debt due to affiliate at December 31 was:

<TABLE>
<CAPTION>
1998 1999
-------- ----------
(IN THOUSANDS)
<S> <C> <C>
Note due 2001............................................... $215,000 $ 225,000
Note due 2002............................................... -- 780,000
Note due 2005............................................... 345,000 345,000
-------- ----------
$560,000 $1,350,000
======== ==========
</TABLE>

On December 9, 1999, Phillips Gas Company declared and distributed a
dividend to Phillips in the form of a note payable in the amount of $780
million. The note payable is due in full at maturity on December 9, 2002, bears
interest at a rate of 5.74 percent per annum, and may be paid prior to maturity
at any time without penalty or premium. The amount of the dividend exceeded the
company's historical-cost-based net assets, resulting in a negative balance in
stockholder's equity.

The declaration and payment of dividends is at the discretion of the
company's Board of Directors. In connection with each dividend declaration, the
Board of Directors makes a determination that, based upon its familiarity with
the company's business, prospects and financial condition, the company's recent
earnings history and forecast, an appraisal of the company's assets and
discussions with the company's executive officers, attorneys and accountants,
the dividend is a permitted dividend under Delaware law. This determination was
made prior to the declaration of the $780 million dividend made on December 9,
1999.

The note due 2001 bears interest at LIBOR plus 1/2 percent per annum (6.33
percent at December 31, 1999). Any amount repaid may be reborrowed as long as
the agreement is in effect. The note due 2005 bears interest at the applicable
federal mid-term rate (6.03 percent monthly rate for December 1999). The
carrying amount of the floating-rate debt approximates fair value.

7. FINANCIAL INSTRUMENTS

Concentrations of Credit Risk

The company's financial instruments that are exposed to concentrations of
credit risk consist primarily of cash equivalents, accounts receivable and
over-the-counter derivative contracts. Derivative contracts are immaterial to
the financial statements of the company.

The company's cash and cash equivalents are held by Phillips as part of its
centralized cash management system. Cash equivalents are in high-quality
securities placed with major international banks and financial institutions.
Phillips' investment policy limits the company's exposure to concentrations of
credit risk with respect to its cash equivalent investments.

The company's affiliate receivables result primarily from its sales of
natural gas liquids and residue gas to Phillips. The company's trade receivables
result primarily from domestic sales of residue gas to local distribution
companies, electric utilities, various other business and industrial end-users,
and marketers. The company routinely assesses the financial strength of its
unaffiliated residue-gas customers. The company considers its concentrations of
credit risk, other than those with Phillips, to be limited.

F-48
<PAGE> 100
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

Fair Values of Financial Instruments

The following methods and assumptions were used by the company in
estimating the fair value of its financial instruments:

Cash and cash equivalents: The carrying amount reported in the balance
sheet approximates fair value because of the short-term nature of these
investments.

Deferred purchase obligation due within one year: The carrying amount
reported in the balance sheet approximates fair value because of the
short-term nature of the obligation.

Long-term debt: The carrying amount of the company's floating- and
fixed-rate debt approximates fair value based on current market rates.

8. PREFERRED STOCK

On December 15, 1997, the company redeemed its 13,800,000 shares of Series
A 9.32% Cumulative Preferred Stock at par. The liquidation value for each Series
A preferred share was $25, plus $.2006 for unpaid dividends.

9. CONTINGENT LIABILITIES

The company is a party to a number of legal proceedings pending in various
courts or agencies for which no provision has been made. Costs related to
contingencies are provided when a loss is probable and the amount can be
reasonably estimated. These accruals are not discounted for delays in future
payment and are not reduced for potential insurance recoveries. If applicable,
undiscounted receivables are accrued for probable insurance recoveries.

A judgment has been entered in the case of Chevron U.S.A., Inc. versus GPM
Gas Corporation (GPM), a wholly owned subsidiary of the company, upholding and
construing most favored nations clauses in three 1961 West Texas gas purchase
contracts. Although a federal district court decided that GPM owes Chevron
damages in the amount of $13,828,030 through July 31, 1998, plus 6 percent
interest from that date and attorneys' fees in the amount of $329,994, GPM has
appealed the judgment to the U.S. Court of Appeals for the Fifth Circuit.

Based on currently available information, after taking into consideration
amounts already accrued and the pending appeal in the Chevron litigation, PGC
believes that any liability resulting from any of the above matters will not
have a material adverse effect on its financial statements. However, such
matters could have a material effect on results of operations in a particular
quarter or fiscal year as they develop or as new issues are identified.

10. RELATED PARTY TRANSACTIONS

Significant transactions with affiliated parties were:

<TABLE>
<CAPTION>
1997 1998 1999
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues(a)................................ $758,700 $537,528 $725,478
Gas purchases(b)..................................... 118,827 76,617 100,253
Operating expenses(c)(e)(h).......................... 115,698 113,475 110,897
Selling, general and administrative
expenses(c)(d)(e).................................. 12,828 10,059 13,306
Interest income(f)................................... 2,701 2,430 2,487
Interest expense(g).................................. 20,340 35,880 35,610
</TABLE>

F-49
<PAGE> 101
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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

(a) The company sells a portion of its residue gas and other by-products to
Phillips at contractual prices that approximate market prices. The company
sells substantially all of its natural gas liquids to Phillips at prices
based upon quoted market prices for fractionated natural gas liquids, less
charges for transportation, fractionation and quality-adjustment fees.
Effective January 1, 2000, the pricing formula contained in the natural gas
liquids supply arrangement with Phillips was renegotiated, as allowed under
the contract, to reflect current market conditions. The new arrangement
will be maintained for an initial term of 15 years. PGC believes that the
loss of Phillips as a natural gas liquids customer would have a material,
adverse effect on its revenues and operating results.

(b) The company purchases raw gas from Phillips at contractual prices that
approximate market prices. During 1999, Phillips provided the company with
approximately 8 percent of its raw gas throughput, under long-term supply
contracts, making Phillips its largest single supplier. PGC believes that
the loss of Phillips as a raw gas supplier would have a material adverse
effect on its dedicated raw gas supplies and its operating results.

(c) Phillips provides the company with various field services (costs included
in operating expenses) and other general administrative services (costs
included in selling, general and administrative expenses) including
insurance, personnel administration, office space, communications, data
processing, engineering, automotive and other field equipment, and other
miscellaneous services. Charges for these services and benefits are based
on usage and actual costs or other allocation methods the company considers
reasonable.

(d) Phillips charges the company a portion of its corporate indirect overhead
costs including executive, legal, treasury, planning, tax, auditing and
other corporate services, under an administrative services agreement.
Charges for these services and benefits are based on usage and actual costs
or other allocation methods the company considers reasonable.

(e) All operational and staff personnel requirements are met by Phillips'
employees, most of whom are associated with the GPM Gas Services Company
division of Phillips. All services provided by Phillips, including (c) and
(d) above, are priced to reimburse Phillips for its actual costs. Charges
for these services and benefits are based on usage and actual costs or
other allocation methods the company considers reasonable. Selling, general
and administrative expenses included a severance charge reversal of $2
million in 1998, and a $2 million severance charge in 1999.

(f) The company earns interest from participation in Phillips' centralized cash
management system.

(g) The company incurs interest expense on borrowings from and debt to
Phillips.

(h) Beginning January 1, 1994, the company began paying GGG a fee for gas
gathering services under a long-term contract. The gas gathering fee
structure in the long-term contract contains a component that is paid to
GGG in an accelerated manner. Because GGG is providing the same gas
gathering services to the company over the contract period, recognition of
expenses related to this component of the gathering fee is deferred and
recognized on a straight-line basis through the remaining period of the
long-term contract. In 1997, 1998 and 1999, the total gathering fees were
$42,755,000, $42,951,000 and $41,447,000, respectively, of which
$34,952,000, $35,720,000 and $34,316,000, respectively, were expensed.

The company provides Phillips with other minor administrative services.
Costs allocated to Phillips for these services have been netted against the
above direct charges from Phillips and were $120,000, $79,000 and $72,000 in
1997, 1998 and 1999, respectively.

The company periodically buys from, or sells to, Phillips various assets
used in the operations of the business. These net acquisitions were recorded at
the assets' historical net book values, which generally approximated fair market
value, and totaled $22,000, $60,000 and $239,000 in 1997, 1998 and 1999,

F-50
<PAGE> 102
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

respectively. Prior to such acquisition or sale, the company paid or received a
fee based on usage of such assets (included in operating expenses above). In
addition, the company purchases plastic pipe from Phillips, which is used in the
construction of gathering systems. Purchases in 1997, 1998 and 1999 were
$3,942,000, $2,276,000 and $2,175,000, respectively.

11. EMPLOYEE BENEFIT PLANS

Substantially all employees of Phillips' GPM Gas Services Company division
participate in Phillips' benefit plans, including pension plans, defined
contribution plans, stock option plans and health and life insurance plans.
Costs are allocated to the company based principally on base payroll costs of
participating employees. Total benefit plan costs charged to the company were
$22,095,000, $22,522,000 and $21,005,000 for the years ended 1997, 1998 and
1999, respectively.

12. INCOME TAXES

Taxes charged to income were:

<TABLE>
<CAPTION>
1997 1998 1999
------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal
Current.............................................. $17,117 $(23,339) $19,072
Deferred............................................. 31,114 40,747 25,646
State
Current.............................................. 443 215 558
Deferred............................................. 6,324 3,912 6,968
------- -------- -------
$54,998 $ 21,535 $52,244
======= ======== =======
</TABLE>

Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Major components of the
company's deferred taxes at December 31 were:

<TABLE>
<CAPTION>
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Deferred Tax Liabilities
Depreciation................................................ $164,065 $188,829
Prepaid gas gathering fees.................................. 17,612 20,374
-------- --------
Total deferred tax liabilities.............................. 181,677 209,203
-------- --------
Deferred Tax Assets
Alternative minimum tax credit carryforward................. 55,385 55,385
Net operating loss carryforwards............................ 45,104 36,312
Deferred gain on sale of assets............................. 6,495 6,062
Investment in partnerships.................................. 3,553 4,549
Contingency accruals........................................ 2,973 4,924
Benefit plan accruals....................................... 1,715 2,030
Other (net)................................................. 452 1,327
-------- --------
Total deferred tax assets................................... 115,677 110,589
-------- --------
Net deferred tax liabilities................................ $ 66,000 $ 98,614
======== ========
</TABLE>

F-51
<PAGE> 103
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

The tax bases in the company's assets were increased as a result of the
1992 transfer of substantially all of its assets to GPM Gas Corporation and the
subsequent issuance and sale of preferred stock. The net operating loss
carryforwards and the alternative minimum tax credit carryforwards resulted
primarily from tax depreciation on the increased bases in the company's assets.

The company believes it is more likely than not that it will fully realize
its deferred tax assets, and, accordingly, a valuation allowance has not been
provided. Management expects that the deferred tax assets will be realized as
reductions in future taxable operating income or by utilizing available tax
planning strategies. Uncertainties that may affect the realization of these
assets include tax law changes, change in control as discussed in Note 16, and
the future level of product costs. Therefore, the company periodically reviews
its ability to realize these assets and will establish a valuation allowance if
needed.

At December 31, 1999, the company had net operating loss carryforwards of
$71 million for U.S. income tax purposes, and $221 million for state income tax
purposes. The U.S. income tax carryforwards begin expiring in 2009, and the
state income tax carryforwards begin expiring in 2000. The alternative minimum
tax credit can be carried forward indefinitely to reduce the company's regular
tax liability.

The reconciliation of income tax at the federal statutory rate with the
provision for income taxes follows:

<TABLE>
<CAPTION>
PERCENT OF
PRETAX INCOME
------------------
1997 1998 1999 1997 1998 1999
------- ------- ------- ---- ---- ----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Federal statutory income tax....... $50,752 $18,497 $46,892 35.0% 35.0% 35.0%
State income tax................... 4,399 2,683 4,893 3.0 5.1 3.7
Other.............................. (153) 355 459 (0.1) 0.6 0.3
------- ------- ------- ---- ---- ----
$54,998 $21,535 $52,244 37.9% 40.7% 39.0%
======= ======= ======= ==== ==== ====
</TABLE>

13. KEEP WELL REPLACEMENT AGREEMENT

The redemption of the company's outstanding shares of Series A 9.32%
Cumulative Preferred Stock on December 15, 1997, cancelled the previous Keep
Well Agreement and triggered the need for a Keep Well Replacement Agreement
between Phillips and PGC. The Keep Well Replacement Agreement provides for
Phillips to maintain PGC's consolidated tangible net worth in an amount not less
than $50 million, or to irrecoverably and unconditionally guaranty the full and
timely performance, payment and discharge by PGC of all its obligations and
liabilities. Effective February 1, 2000, Phillips furnished a guaranty to GGG
assuring payment by PGC of all its existing or future obligations and
liabilities to GGG.

F-52
<PAGE> 104
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

14. CASH FLOW INFORMATION

<TABLE>
<CAPTION>
1997 1998 1999
------- ------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Non-Cash Investing and Financing Activities
Liquidating dividend to parent company in the form of a
promissory note...................................... $ -- $ -- $780,000
Deferred payment obligation to purchase property, plant
and equipment........................................ -- -- 8,300
Cash Payments
Interest............................................... 20,452 36,108 32,789
Income taxes, including payments to Phillips........... 25,432 123 20,773
</TABLE>

The deferred purchase obligation resulted from the company's July 1, 1999,
purchase of American Liberty Oil Company's interest in the Artesia plant and
gathering system in New Mexico. At the time of closing, a partial cash payment
was made. A second and final payment was made on January 3, 2000.

15. OTHER FINANCIAL INFORMATION

<TABLE>
<CAPTION>
1997 1998 1999
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Taxes other than income and payroll taxes............... $10,765 $10,772 $12,626
</TABLE>

16. PROPOSED BUSINESS COMBINATION

On December 16, 1999, Phillips and Duke Energy Corporation (Duke Energy)
announced that they had signed definitive agreements to combine the two
companies' gas gathering, processing and marketing businesses to form a new
midstream company to be called Duke Energy Field Services, LLC (Field Services
LLC). The definitive agreements have been unanimously approved by both
companies' Boards of Directors. Subject to regulatory approval, the transaction
is expected to close by the end of the first quarter of 2000.

If the transaction closes as expected, the subsidiaries of PGC will be
contributed to Field Services LLC in a partially tax-free exchange, and those
subsidiaries will cease to be wholly owned subsidiaries of Phillips. As part of
the transaction, the existing natural gas liquids purchase contract between
Phillips and the company will be maintained by the new company for an initial
term of 15 years. At closing, Duke Energy will own about 70 percent of Field
Services LLC, and Phillips will own about 30 percent.

17. IMPACT OF TRANSITION TO YEAR 2000 (UNAUDITED)

PGC relies on Phillips for computer systems, hardware and software for
operation of its facilities and business support systems. PGC's operations and
facilities were included as part of Phillips' companywide Year 2000 Project that
addressed the issue of computer programs and embedded computer chips being
unable to distinguish between the year 1900 and the year 2000. That project is
now complete. With the rollover into 2000, neither PGC nor Phillips experienced
any significant Year 2000 failures. Some minor Year 2000 issues occurred and
were resolved, but none have had a material impact on PGC's results of
operations, liquidity, financial condition or safety record. The total costs
associated with Year 2000 issues were not material to PGC's or Phillips'
financial position. Phillips continues to monitor its mission-critical computer
applications and those of its suppliers and vendors throughout the year 2000 to
ensure that any latent Year 2000 matters that may arise are addressed promptly.

F-53
<PAGE> 105

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS)

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1999 2000
-------- --------
(UNAUDITED)
<S> <C> <C>
REVENUES
Natural gas liquids......................................... $104,035 $286,961
Residue gas................................................. 141,706 224,524
Other....................................................... 19,910 33,345
-------- --------
Total Revenues......................................... 265,651 544,830
-------- --------
COSTS AND EXPENSES
Gas purchases............................................... 189,421 377,659
Operating expenses.......................................... 42,741 47,285
Selling, general and administrative expenses................ 4,880 4,251
Depreciation................................................ 19,262 20,700
Interest expense............................................ 7,255 20,492
-------- --------
Total Costs and Expenses............................... 263,559 470,387
-------- --------
Income before income taxes.................................. 2,092 74,443
Provision for income taxes.................................. 851 29,110
-------- --------
NET INCOME.................................................. $ 1,241 $ 45,333
======== ========
</TABLE>

See Notes to Financial Statements.

F-54
<PAGE> 106

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1999 2000
-------- --------
(UNAUDITED)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income.................................................. $ 1,241 $ 45,333
Adjustments to reconcile net income to net cash provided by
operating activities
Non-working capital adjustments
Depreciation......................................... 19,262 20,700
Deferred taxes....................................... 5,783 13,891
Deferred gathering fees.............................. (1,679) (1,651)
Gain on sale of assets............................... (212) (88)
Other................................................ 337 1,896
Working capital adjustments
Decrease (increase) in accounts receivable........... 4,028 (13,646)
Decrease (increase) in inventories................... 1,000 (298)
Decrease in prepaid expenses and other current
assets, including deferred taxes.................. 555 14,338
Decrease in accounts payable......................... (17,224) (64,535)
Decrease in taxes and other accruals................. (1,875) (753)
-------- --------
Net Cash Provided by Operating Activities................... 11,216 15,187
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and investments........................ (13,532) (11,985)
Proceeds from asset dispositions............................ 55 673
-------- --------
Net Cash Used for Investing Activities...................... (13,477) (11,312)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of note payable..................................... -- (8,300)
-------- --------
Net Cash Used for Financing Activities...................... -- (8,300)
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS..................... (2,261) (4,425)
Cash and cash equivalents at beginning of period............ 27,045 164,078
-------- --------
Cash and Cash Equivalents at End of Period.................. $ 24,784 $159,653
======== ========
</TABLE>

See Notes to Financial Statements.

F-55
<PAGE> 107

PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS

1. INTERIM FINANCIAL INFORMATION

The financial information for the interim periods presented in the
financial statements included in this report is unaudited and includes all known
accruals and adjustments that Phillips Gas Company (PGC or the company)
considers necessary for a fair statement of the results for such periods. All
such adjustments are of a normal and recurring nature.

2. BUSINESS COMBINATION

On March 31, 2000, Phillips Petroleum Company (Phillips) combined its gas
gathering, processing and marketing business with Duke Energy Corporation's
(Duke Energy) gas gathering, processing and marketing business to form a new
midstream company called Duke Energy Field Services LLC (DEFS).

PGC contributed its holdings in its limited-liability-company subsidiaries
to DEFS in a partially tax-free exchange. The operations of these subsidiaries
comprise substantially all of the operations of PGC. Effective March 31, 2000,
the company is accounting for its investment in DEFS using the equity method.

In connection with the combination DEFS borrowed approximately $2.75
billion of short-term debt. In April 2000, the proceeds of the debt were used to
make one-time cash distributions of approximately $1,525 million to Duke Energy
and $1,220 million to Phillips. Duke Energy owns about 70 percent of DEFS, and
Phillips, through PGC, owns about 30 percent.

3. INCOME TAXES

The company's effective tax rate for the first three months of 1999 was 41
percent, compared with 39 percent for the same period of 2000.

Deferred income taxes are computed using the liability method and provided
on all temporary differences between the financial reporting basis and the tax
basis of the assets and liabilities. Allowable tax credits are applied currently
as reductions of the provision for income taxes. The results of operations for
1999 and 2000 are included in the consolidated federal income tax return of
Phillips, with any resulting tax liability or refund settled with Phillips on a
current basis. Income tax expense represents PGC on a separate return basis,
except that the same principles and elections used in the consolidated return
were applied.

4. RELATED PARTY TRANSACTIONS

Significant transactions with affiliated parties were:

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1999 2000
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Operating revenues.......................................... $110,613 $287,294
Gas purchases............................................... 17,970 35,499
Operating expenses.......................................... 27,363 29,509
Selling, general and administrative expenses................ 4,361 3,750
Interest income............................................. 452 2,618
Interest expense............................................ 7,224 20,474
</TABLE>

Prior to the contribution of its subsidiaries to DEFS on March 31, 2000,
the company purchased raw gas from, and sold a portion of its residue gas and
substantially all of its natural gas liquids to, Phillips.

F-56
<PAGE> 108
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS -- CONTINUED

Phillips also provided the company with various field and general administrative
services. In addition, the company purchased Phillips' plastic pipe, which is
used in the construction of gathering systems.

The company earns interest from participation in Phillips' centralized cash
management system and incurs interest expense on its borrowings from Phillips.

The company paid gathering fees to GPM Gas Gathering L.L.C. (GGG) until it
contributed its equity interest in GGG into DEFS on March 31, 2000. In the first
three months of 1999 and 2000, net fees paid to GGG for gas gathering services
were $10,334,831 and $10,101,951, respectively; $8,655,478 and $8,450,827 were
expensed.

Selling, general and administrative expenses included a $2 million
severance charge during the first three months of 1999.

5. CASH FLOW INFORMATION

NON-CASH INVESTING ACTIVITIES

On March 31, 2000, the company contributed its holdings in its
limited-liability-company subsidiaries to DEFS. The contribution included
property, plant and other assets and liabilities held by these companies, except
for cash invested with Phillips, deferred taxes and current taxes payable.

Other non-cash investing activities and cash payments for the three-month
periods ended March 31 were as follows:

<TABLE>
<CAPTION>
1999 2000
------ -------
(IN THOUSANDS)
<S> <C> <C>
CASH PAYMENTS
Interest.................................................... $7,296 $20,477
Income taxes, including payments to Phillips................ 1,432 21
</TABLE>

F-57
<PAGE> 109

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Management of
Duke Energy Field Services
Denver, Colorado

We have audited the accompanying combined statements of income and cash
flows of the UPFuels Division of Union Pacific Resources Group Inc. (a Utah
Corporation) for the year ended December 31, 1998 and the three-month period
ended March 31, 1999. These financial statements are the responsibility of the
UPFuels Division's management. Our responsibility is to express an opinion on
these financial statements based on our audits.

In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the combined results of operations and cash
flows of the UPFuels Division for the year ended December 31, 1998, and the
three-month period ended March 31, 1999, in conformity with accounting
principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 10, 2000

F-58
<PAGE> 110

INDEPENDENT AUDITORS' REPORT

To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas

We have audited the accompanying combined statements of income and cash
flows for the year ended December 31, 1997 of the UPFuels Division of Union
Pacific Resources Group Inc. (as restated). These financial statements are the
responsibility of the UPFuels Division's management. Our responsibility is to
express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all
material respects, the combined results of operations and cash flows of the
UPFuels Division for the year ended December 31, 1997, in conformity with
generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Fort Worth, Texas
June 12, 1998

F-59
<PAGE> 111

UPFUELS DIVISION

COMBINED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998 AND FOR THE QUARTER ENDED MARCH
31, 1999

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1997 1998 1999
------ -------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues:
Gathering and processing.................................. $321.7 $ 227.2 $ 54.5
Pipelines................................................. 401.2 305.0 75.8
Marketing................................................. 2,761.6 3,062.8 784.0
Intersegment.............................................. (269.3) (188.6) (45.2)
------ -------- --------
Total operating revenues............................ 3,215.2 3,406.4 869.1
------ -------- --------
Product purchases:
Gathering and processing.................................. 157.1 119.6 30.9
Pipelines................................................. 312.4 198.4 44.9
Marketing................................................. 2,728.5 2,986.3 757.9
Intersegment.............................................. (269.3) (188.6) (45.2)
------ -------- --------
Total product purchases............................. 2,928.7 3,115.7 788.5
------ -------- --------
Gross margin:
Gathering and processing.................................. 164.6 107.6 23.6
Pipelines................................................. 88.8 106.6 30.9
Marketing................................................. 33.1 76.5 26.1
------ -------- --------
Total gross margin.................................. 286.5 290.7 80.6
------ -------- --------
Operating expenses:
Gathering and processing.................................. 57.9 66.4 17.7
Pipelines................................................. 27.3 37.3 7.8
Marketing................................................. -- -- --
------ -------- --------
Total operating expenses............................ 85.2 103.7 25.5
------ -------- --------
General & administrative expenses:
Gathering and processing.................................. 6.0 8.0 1.9
Pipelines................................................. 1.3 2.9 0.7
Marketing................................................. 13.0 13.0 3.0
Corporate................................................. 7.0 7.2 2.0
------ -------- --------
Total general & administrative expenses............. 27.3 31.1 7.6
------ -------- --------
Depreciation and amortization expense
Gathering and processing.................................. 44.0 41.6 11.8
Pipelines................................................. 29.4 32.7 8.0
Marketing................................................. 1.1 6.2 4.1
------ -------- --------
Total depreciation and amortization expense......... 74.5 80.5 23.9
------ -------- --------
Operating income (loss):
Gathering and processing.................................. 56.7 (8.4) (7.8)
Pipelines................................................. 30.8 33.7 14.4
Marketing................................................. 19.0 57.3 19.0
Corporate................................................. (7.0) (7.2) (2.0)
------ -------- --------
Total operating income.............................. 99.5 75.4 23.6
------ -------- --------
Other income................................................ -- 0.6 --
Minority interest........................................... (9.8) (7.6) (2.1)
------ -------- --------
Income before income taxes.................................. 89.7 68.4 21.5
Income taxes................................................ 33.2 25.3 8.0
------ -------- --------
Net income.................................................. $ 56.5 $ 43.1 $ 13.5
====== ======== ========
</TABLE>

The accompanying accounting policies and notes to the combined
financial statements are an integral part of these statements.

F-60
<PAGE> 112

UPFUELS DIVISION

COMBINED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998 AND FOR THE QUARTER ENDED MARCH
31, 1999

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1997 1998 1999
------- ------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Cash provided by operations:
Net income................................................ $ 56.5 $ 43.1 $ 13.5
Depreciation and amortization.......................... 74.5 80.5 23.9
Deferred income taxes.................................. 15.1 (24.0) 10.8
Minority interest earnings............................. 9.8 7.6 2.1
Other non-cash charges (credits) -- net................ 8.1 (1.0) (0.4)
Changes in current assets and liabilities................. 14.6 (35.8) 18.0
------- ------- ------
Cash provided by operations....................... 178.6 70.4 67.9
------- ------- ------
Investing activities:
Capital expenditures...................................... (168.5) (143.8) (32.0)
Acquisition of Highlands Gas Corporation.................. (179.4) -- --
Acquisition of certain assets of Norcen................... -- (83.2) --
------- ------- ------
Cash used by investing activities................. (347.9) (227.0) (32.0)
------- ------- ------
Financing activities:
Capital contributions by/(distributions to) Union Pacific
Resources Group Inc. .................................. 187.4 170.0 (39.9)
Distributions to minority interest owners................. (20.2) (11.3) (1.5)
------- ------- ------
Cash provided by (used in) financing activities... 167.2 158.7 (41.4)
------- ------- ------
Net change in cash and temporary investments................ (2.1) 2.1 (5.5)
Balance at beginning of period.............................. 9.5 7.4 9.5
------- ------- ------
Balance at end of period.................................... $ 7.4 $ 9.5 $ 4.0
======= ======= ======
Changes in current assets and liabilities:
Accounts receivable....................................... 1.4 13.1 35.7
Inventories............................................... (15.2) (10.4) 12.7
Other current assets...................................... (5.2) 11.3 0.7
Accounts payable.......................................... 30.5 (45.9) (29.4)
Other current liabilities................................. 3.1 (3.9) (1.7)
------- ------- ------
Total............................................. $ 14.6 $ (35.8) $ 18.0
======= ======= ======
</TABLE>

The accompanying accounting policies and notes to the combined
financial statements are an integral part of these statements.

F-61
<PAGE> 113

UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS

SIGNIFICANT ACCOUNTING POLICIES

Principles of Combination. The combined financial statements include the
accounts of certain gathering, processing, transporting and marketing operations
of companies which are wholly-owned subsidiaries of Union Pacific Resources
Group Inc. ("UPR"), a Utah Corporation. In addition, the combined financial
statements include the operations of certain gathering and processing assets
owned by wholly-owned subsidiaries of UPR that are not included in their
entirety herein. Collectively, these wholly-owned subsidiaries and assets are
considered and referred to herein as the "UPFuels Division" of UPR. All material
intra-divisional transactions have been eliminated.

The UPFuels Division accounts for its investments in pipeline partnerships
and joint ventures under the equity method of accounting for entities owned
20%-50% by the UPFuels Division and fully consolidates entities owned greater
than 50% by the UPFuels Division. The minority interest recorded by the UPFuels
Division represents the ownership of other parties in entities in which the
UPFuels Division owns greater than 50% but less than 100%.

Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions. These estimates and assumptions affect the reported
amounts of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities. Management believes its estimates and
assumptions are reasonable; however, there are a number of risks and
uncertainties which may cause actual results to differ materially from the
estimates.

Depreciation and amortization. Provisions for depreciation of property,
plant and equipment are computed on the straight-line method based on estimated
service lives which range from three to 30 years. The cost of acquired gas
purchase and marketing contracts are amortized using the straight-line method
over the applicable period. Goodwill is being amortized using the straight-line
method over 20 years. Amortization of goodwill was $2.0 million, $4.5 million
and $1.1 million for the years ended December 31, 1997 and 1998 and for the
quarter ended March 31, 1999, respectively. The value of goodwill is
periodically evaluated based on the expected future undiscounted operating cash
flows to determine whether any potential impairment exists.

Revenue Recognition. The UPFuels Division recognizes revenues as gas and
natural gas liquids are delivered and services are rendered. Revenues are
recorded on an accrual basis, including an estimate for gas and natural gas
liquids delivered but unbilled at the end of each accounting period.

Derivative Financial Instruments. Unrealized gains/losses on derivative
financial instruments used for hedging purposes are not recorded. Recognition of
realized gains/losses and option premium payments/receipts are deferred and
recorded in the combined statement of income when the underlying physical
product is purchased or sold. The cash flow impact of derivative and other
financial instruments is reflected in cash provided by operations in the
combined statements of cash flows.

Income Taxes. The UPFuels Division is included in the consolidated Federal
income tax return of UPR. The consolidated Federal income tax liability of UPR
is allocated among all corporate entities on the basis of the entity's
contributions to the consolidated Federal income tax liability. Full benefit of
tax losses and credits made available and utilized in UPR's consolidated Federal
income tax returns are being allocated to the individual companies generating
such items. Income tax expense represents federal income taxes as if the company
were filing a separate return.

Environmental Expenditures. Environmental expenditures related to treatment
or cleanup are expensed when incurred, while environmental expenditures which
extend the life of the property or prevent future contamination are capitalized
in accordance with generally accepted accounting principles. Liabilities for
these expenditures are recorded when it is probable that obligations have been
incurred and

F-62
<PAGE> 114
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

the amounts can be reasonably estimated, based on current law and existing
technologies. Environmental accruals are recorded at undiscounted amounts and
exclude claims for recoveries from insurance or other third parties.

Earnings Per Share. Earnings per share have been omitted from the combined
statements of income as the UPFuels Division was wholly owned by UPR for all
periods presented.

1. NATURE OF OPERATIONS

The UPFuels Division owns and operates natural gas and natural gas liquids
gathering and pipeline systems and gas processing plants and is engaged in the
business of purchasing, gathering, processing, transporting, storing and
marketing natural gas and natural gas liquids. Through a related party
transaction, the UPFuels Division markets a substantial portion of UPR's natural
gas and natural gas liquid production together with significant volumes of
natural gas and natural gas liquids produced by others. The UPFuels Division has
a diverse customer base for its hydrocarbon products.

The UPFuels Division's results of operations are largely dependent on the
difference between the prices received for its hydrocarbon products and the cost
to acquire and market such resources. Hydrocarbon prices are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the control of the UPFuels Division. These factors include
worldwide political instability, the foreign supply of oil and natural gas, the
price of foreign imports, the level of consumer demand and the price and
availability of alternative fuels. Historically, the UPFuels Division has been
able to manage a portion of the operating risk relating to hydrocarbon price
volatility through hedging activities.

2. ACQUISITION OF THE UPFUELS DIVISION BY DUKE ENERGY FIELD SERVICES INC.

In November 1998, UPR reached an agreement with Duke Energy Field Services,
Inc. whereby Duke Energy Field Services would acquire certain gathering,
processing, pipeline and marketing assets of UPR. The sale transaction closed
effective March 31, 1999, with the purchase price being $1.35 billion. Certain
liabilities primarily income tax and retiree benefits obligations, were not
assumed by Duke Energy Field Services in connection with the sale transaction.

3. RELATED PARTY TRANSACTIONS

The UPFuels Division enters into certain natural gas and crude hedging
transactions on behalf of UPR. Services performed by UPR on behalf of the
UPFuels Division include cash management, internal audit and tax and employee
benefits administration. In the UPFuels Division originally issued financial
statements, there was no cost allocated for these services. The UPFuels Division
management subsequently determined that $2.0 million, $2.0 million and $0.5
million for 1997, 1998 and the three months ended March 31, 1999, respectively,
should have been allocated. As a result, the accompanying financial statements
have been revised from their original presentation. Other general and
administrative expenses have been allocated to the UPFuels Division, including
office rent expense. Since treasury is considered to be a UPR corporate
function, no interest expense has been allocated to the UPFuels Division in the
accompanying combined statements of income.

The UPFuels Division has a buy/sell agreement with UPR. Under this
agreement, the UPFuels Division gathers, transports, processes and sells natural
gas and natural gas liquids for UPR and purchases natural gas and natural gas
liquids from UPR.

The charges for allocated services are based on estimated full time
equivalent headcount at fully burdened rates. The buy/sell arrangements are
based on prevailing market conditions in each regional area. Accordingly, these
transactions reflect UP Fuels results as if they were on a stand alone basis.

F-63
<PAGE> 115
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

The following table reflects the intercompany balance outstanding at each
period end as well as the high and low balance for each period.

<TABLE>
<CAPTION>
AVERAGE
BALANCE HIGH LOW
OUTSTANDING BALANCE BALANCE
----------- ------- -------
($ IN MILLIONS)
<S> <C> <C> <C>
1997...................................................... $ 93.7 $187.4 $ 0
1998...................................................... $272.4 $357.4 $187.5
First Quarter 1999........................................ $337.5 $357.4 $317.5
</TABLE>

The following table summarizes product purchases, in volumes and dollars,
made by the UPFuels Division from UPR during each of the years ended December
31, 1997 and 1998 and the quarter ended March 31, 1999:

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1997 1998 1999
------ ------ ---------
(VOLUMES)
<S> <C> <C> <C>
Gas (MMcf/day).............................................. 860.8 923.1 846.2
Natural gas liquids (Mbbls/day)............................. 68.8 68.5 63.1
(MILLIONS OF DOLLARS)
Gas......................................................... $628.4 $630.1 $140.1
Natural gas liquids......................................... $281.3 $203.5 $ 43.3
</TABLE>

4. SIGNIFICANT ACQUISITION

Highlands Gas Corporation. In August 1997, the UPFuels Division acquired
100% of the outstanding stock of Highlands Gas Corporation ("Highlands") for an
adjusted purchase price of approximately $179.4 million. Highlands is in the
business of gathering, purchasing, processing and transporting natural gas and
natural gas liquids. The acquisition included three natural gas processing
plants, five gathering systems with over 700 miles of gas and natural gas
liquids gathering pipeline and 400 miles of transportation pipeline located in
Western Texas and Eastern New Mexico. Results of operations for Highlands
subsequent to the acquisition date are included in the consolidated statements
of income.

The following unaudited pro forma combined results of operations for the
year ended December 31, 1997 are presented as if the Highlands acquisition had
been made at the beginning of the year. The unaudited pro forma information is
not necessarily indicative of either the results of operations that would have
occurred had the purchase been made during the periods presented or the future
results of the combined operations.

PRO FORMA RESULTS

<TABLE>
<CAPTION>
1997
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Revenues........................................ $3,376.8
Operating income................................ 96.3
Net income...................................... $ 54.5
</TABLE>

F-64
<PAGE> 116
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

5. FINANCIAL INSTRUMENTS

Hedging. The UPFuels Division has established policies and procedures for
managing risk within its organization. It is balanced by internal controls and
governed by a risk management committee. The level of risk assumed by the
UPFuels Division is based on its objectives and earnings, and its capacity to
manage risk. Limits are established for each major category of risk, with
exposures monitored and managed by UPFuels Division management, and reviewed
semi-annually by the risk management committee. Major categories of the UPFuels
Division's risk are defined as follows:

Commodity Price Risk -- Non-Trading Activities. The UPFuels Division uses
derivative financial instruments for non-trading purposes in the normal course
of business to manage and reduce risks associated with contractual commitments,
price volatility, and other market variables in conjunction with transportation,
storage, and customer service programs. These instruments are generally put in
place to limit risk of adverse price movements, however, when this is done,
these same instruments usually limit future gains from favorable price
movements. Such risk management activities are generally accomplished pursuant
to exchange-traded contracts or over-the-counter options.

Recognition of realized gains/losses and option premium payments/receipts
are also deferred in the combined statements of income until the underlying
physical product is sold. Unrealized gains/losses on derivative financial
instruments are not recorded. The cash flow impact of derivative and other
financial instruments is reflected as cash flows provided from operations in the
combined statements of cash flows.

Commodity Price Risk -- Trading Activities. Periodically, the UPFuels
Division may enter into transactions involving a wide range of energy related
derivative financial transactions that are not the result of hedging activities.
These instruments are generally put into place based on the UPFuels Division's
analysis and expectations with respect to price movement or changes in other
market variables. As of March 31, 1999, there were no transactions in place
which would materially affect the results of operations or financial condition
of the UPFuels Division.

Credit Risk. Credit risk is the risk of loss as a result of nonperformance
by counterparties pursuant to the terms of their contractual obligations.
Because the loss can occur at some point in the future, a potential exposure is
added to the current replacement value to arrive at a total expected credit
exposure. The UPFuels Division has established methodologies to establish
limits, monitor and report creditworthiness and concentrations of credit to
reduce such credit risk. At March 31, 1999, the UPFuels Division's largest
credit risk associated with any single counterparty, represented by the net fair
value of open contracts with such counterparty was $2.2 million.

Performance Risk. Performance risk results when a counterparty fails to
fulfill its contractual obligations such as commodity pricing or volume
commitments. Typically, such risk obligations are defined within the trading
agreements. The UPFuels Division utilizes its credit risk methodology to manage
performance risk.

Concentrations of Credit Risk. Financial instruments which subject the
UPFuels Division to concentrations of credit risk consist principally of trade
receivables and short-term cash investments. A significant portion of the
UPFuels Division's trade receivables relate to customers in the energy industry,
and, as such, the UPFuels Division is directly affected by the economy of that
industry. However, excluding the relationship with UPR, the credit risk
associated with trade receivables is minimized by the UPFuels Division's diverse
customer base which includes local gas distribution companies, power generation
facilities, pipelines, industrial plants and other wholesale marketing
companies. Ongoing procedures are in place to monitor the creditworthiness of
customers. The UPFuels Division generally requires no collateral from its
customers and historically has not experienced significant losses on trade
receivables.

F-65
<PAGE> 117
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

6. INCOME TAXES

The UPFuels Division is included in the consolidated Federal income tax
return of UPR. The consolidated Federal income tax liability of UPR is allocated
among all corporate entities on the basis of the entity's contributions to the
consolidated Federal income tax liability. Full benefit of tax losses and
credits made available and utilized in UPR's consolidated Federal income tax
returns are being allocated to the individual companies generating such items.

Components of income tax expense for the years ended December 31, 1997 and
1998 and for the quarter ended March 31, 1999.

<TABLE>
<CAPTION>
1997 1998 1999
----- ------ -----
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current:
Federal.................................................. $17.2 $ 46.7 $(2.7)
State.................................................... .9 2.6 (0.1)
----- ------ -----
Total current.................................... 18.1 49.3 (2.8)
Deferred:
Federal.................................................. 14.2 (22.7) 10.2
State.................................................... 0.9 (1.3) 0.6
----- ------ -----
Total deferred...................................... 15.1 (24.0) 10.8
----- ------ -----
Total............................................ $33.2 $ 25.3 $ 8.0
===== ====== =====
</TABLE>

A reconciliation between statutory and effective tax rates for the years
ended December 31, 1997 and 1998 and for the quarter ended March 31, 1999 is as
follows:

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
Statutory tax rate.......................................... 35.0% 35.0% 35.0%
State taxes -- net.......................................... 2.0% 2.0% 2.0%
---- ---- ----
Effective tax rate........................................ 37.0% 37.0% 37.0%
==== ==== ====
</TABLE>

All tax years prior to 1986 have been closed with the Internal Revenue
Service ("IRS"). On behalf of the UPFuels Division, UPR, through Union Pacific
Corporation ("UPC"), is negotiating with the Appeals Office concerning 1986
through 1989. The IRS is examining UPR's returns for 1990 through 1994 in
connection with the IRS' examination of UPC's returns. The UPFuels Division
believes it has adequately provided for Federal and state income taxes.

F-66
<PAGE> 118
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

7. LEASES

The UPFuels Division leases certain compressors and other property. Future
minimum lease payments for operating leases with initial non-cancelable lease
terms in excess of one year as of March 31, 1999, are as follows:

<TABLE>
<CAPTION>
(MILLIONS OF DOLLARS)
<S> <C>
1999............................................ $ 1.9
2000............................................ 2.5
2001............................................ 2.4
2002............................................ 1.5
2003............................................ 1.2
Later years..................................... 5.4
-----
Total minimum payments................ $14.9
=====
</TABLE>

Rent expense for operating leases with terms exceeding one year was $1.1
million and $1.3 million for the years ended December 31, 1997 and 1998,
respectively, and $0.5 million for the quarter ended March 31, 1999. Currently
there is no sublease income for the next five years or thereafter.

8. EMPLOYEE STOCK OPTION PLANS

Stock Option and Retention Stock Plans. Pursuant to the UPR's stock option
and retention stock plans, UPR stock options under the plans are granted at 100%
of fair market value at the date of grant, become exercisable no earlier than
one year after grant and are exercisable for a period of up to eleven years from
grant date. Option grants have been made to directors, officers and employees
and vest over a period up to ten years from the grant date.

Retention shares of UPR common stock are awarded under the plans to
eligible employees, subject to forfeiture if employment terminates during the
prescribed retention period, generally one to five years from grant. Multi-year
retention stock awards also have been made, with vesting two to five years from
grant.

Expense related to these stock option and retention stock programs of UPR,
which pertain to UPFuels Division employees, amounted to $1.2 million, $1.3
million and $.7 million for the years ended 1997 and 1998 and the quarter ended
March 31, 1999, respectively.

Since UPR applies the intrinsic value method in accounting for its stock
option and retention stock plans, it generally records no compensation cost for
its stock option plans. Had compensation cost for UPR's stock option plan been
determined based on the fair value at the grant dates for awards to UPFuels
Division employees under the plan and for options that were converted at the
times of the initial public offering and spin-off of UPR from UPC, the UPFuels
Division's net income would have been reduced by $.6 million, $1.9 million and
$0.1 million for the years ended December 31, 1997 and 1998 and the quarter
ended March 31, 1999, respectively.

Employee Stock Ownership Plan. Effective January 2, 1997, UPR instituted an
employee stock ownership plan ("ESOP"). The ESOP purchased 3.7 million shares or
$107.3 million of newly issued common stock (the "ESOP Shares") from UPRG, which
will be used to fund UPR's matching obligation under its 401(k) Thrift Plan. All
regular employees of the UPFuels Division are eligible to participate in the
ESOP.

During the years ended December 31, 1997 and 1998, and the quarter ended
March 31, 1999, compensation cost related to the allocation of ESOP shares to
participants' accounts was $1.4 million, $1.6 million and $0.4 million,
respectively, for the UPFuels Division.

F-67
<PAGE> 119
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

9. ENVIRONMENTAL EXPOSURE

The UPFuels Division generates and disposes of hazardous and nonhazardous
waste in its current and former operations and is subject to increasingly
stringent Federal, state and local environmental regulations. Certain Federal
legislation imposes joint and several liability for the remediation of various
sites; consequently, the UPFuels Division's ultimate environmental liability may
include costs relating to other parties in addition to costs relating to its own
activities at each site. In addition, the UPFuels Division is or may be liable
for certain environmental remediation matters involving existing or former
facilities.

The UPFuels Division has recorded environmental reserves related to future
costs of all sites where the UPFuels Division's obligation is probable and where
such costs reasonably can be estimated. This accrual includes future costs for
remediation and restoration of sites, as well as for ongoing monitoring costs,
but excludes any anticipated recoveries from third parties.

The UPFuels Division also is involved in reducing emissions, spills and
migration of hazardous materials. Remediation of identified sites and control of
environmental exposures required $1.2 million in 1998 and no spending for the
quarter ended March 31, 1999.

10. COMMITMENTS AND CONTINGENCIES

The UPFuels Division is party to several long-term firm gas transportation
agreements, the largest of which are with Kern River Gas Transportation Company
("Kern River"), Texas Gas Transmission Corporation ("Texas Gas"), and Pacific
Gas Transmission ("PGT"). At December 31, 1997, the UPFuels Division had a keep
whole agreement with UPR which expired at the end of 2003 whereby UPR reimbursed
the UPFuels Division for the excess of the contractual fixed price over the
prevailing market price for the transportation. Conversely, the UPFuels
Division, under the keep whole agreement, was to pay UPR when the prevailing
market price exceeded the contractual fixed price. Accordingly, at December 31,
1997, the UPFuels Division recorded a reserve for the fair value of the
difference between the fixed rate under the firm transportation agreements and
the estimated market rates for the period from 2004 to the end of the respective
contract periods. At December 31, 1997, the reserves, which were included in
other long-term liabilities, were $13.0 million, $5.5 million, and $7.6 million
for the Kern River, Texas Gas, and PGT agreements, respectively.

In conjunction with the sale of the UPFuels Division to Duke Energy Field
Services, Inc. during 1998 the UPFuels Division extended the keep whole
agreement with UPR to cover a 10 year period commencing March 1, 1999 or through
the expiration of the contract, whichever is earlier. In addition, UPR retained
the transportation contract with Kern River. Accordingly, no reserves for the
Kern River and Texas Gas Agreements were recorded at December 31, 1998 or March
31, 1999 and $17.6 million was recorded at December 31, 1998 and March 31, 1999
for the PGT agreement, reflecting additional liabilities for volumes acquired in
1998, partially offset by the extension of the keep whole agreement. During
1998, $8.5 million was recorded as a change in divisional equity for the change
in the keep whole agreement. A detailed explanation of the three major long-term
firm transportation agreements are as follows:

Under the Kern River transportation agreement which expires in 2007, the
UPFuels Division has the right to transport 75 MMcfd of gas on the Kern River
Pipeline system which extends from Opal, Wyoming, to an interconnection with the
Southern California Gas Company pipeline system in southern California. Nine
years remain on the primary term of the agreement, and the current
transportation rate is $0.69 per Mcf. Thereafter, this rate can change based on
Kern River's cost of service and upon rate regulation policies of the Federal
Energy Regulatory Commission ("FERC"). Under a 1993 ruling of the FERC, the
UPFuels Division is obligated to pay all of the fixed costs included in the
transportation rate,

F-68
<PAGE> 120
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

whether or not the UPFuels Division actually uses Kern River's pipeline to
transport gas. Those fixed costs presently amount to $0.61 per Mcf. The
undiscounted amount of the nine year fixed cost commitment, assuming no future
changes in the rate, is $136 million. The 1993 FERC ruling was issued
notwithstanding a provision in the transportation agreement between Kern River
and the UPFuels Division in which the parties agreed that a portion of the fixed
costs would be paid by the UPFuels Division only if and to the extent that the
UPFuels Division uses the pipeline. In light of recent changes in the regulatory
policies of FERC, the UPFuels Division is seeking reinstatement of the
contractually agreed rate structure, but there is no assurance that such efforts
will be successful.

The UPFuels Division is a party to an additional agreement under which it
may acquire, in 2001, at its option, an additional 25 MMcfd of transportation
rights on the Kern River system beginning in 2002.

Under the Texas Gas transportation agreement, which expires in 2008, the
UPFuels Division has the rights to transport 90 MMcfd of gas from the UPFuels
Division's East Texas plant. The UPFuels Division is obligated to pay a fixed
transportation rate of $0.33 per Mmbtu regardless of the volumes transported
under the agreement. The undiscounted amount of this commitment is $104 million.

Under the PGT transportation agreement, which expires in 2023, the UPFuels
Division has the rights to transport 25 MMcfd of gas from Kingsgate, British
Columbia to the California/Oregon border. The UPFuels Division is obligated to
pay a fixed transportation rate of $0.33 per Mmbtu regardless of the volumes
transported under the agreement. However, the UPFuels Division has third party
agreements that reimburse the UPFuels Division for 90 percent of the firm
transportation cost until October 2002. As part of the third party agreements,
the UPFuels Division assigned 50 percent of the firm transportation capacity.
The term for the keep whole agreement for this contract commences on November 1,
2002 and terminates on February 28, 2009. The undiscounted amount of this
commitment, net of the third party reimbursements, is $64 million.

During 1998, the UPFuels Division assumed responsibility for additional
long-term firm transportation agreements with PGT to transport gas from
Kingsgate, British Columbia to the California/Oregon border. Under the
transportation agreements, the UPFuels Division has the rights to transport 106
Mmbtu per day of which 47 Mmbtu per day will expire in October 2007 and the
balance of the contract commitment will expire in October 2023. The UPFuels
Division does have a third party agreement that recovers all the transportation
cost for 20 Mmbtu per day through June 2011.

The UPFuels Division is a defendant in a number of lawsuits and is involved
in governmental proceedings arising in the ordinary course of business,
including contract claims, personal injury claims and environmental claims.
While management of the UPFuels Division cannot predict the outcome of such
litigation and other proceedings, management does not expect those matters to
have a materially adverse effect on the consolidated financial condition or
results of operations of the UPFuels Division.

F-69
<PAGE> 121

PROSPECTUS

$2,000,000,000

DUKE ENERGY FIELD SERVICES, LLC

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

DEBT SECURITIES
---------------------

This prospectus contains summaries of the general terms of these
securities. You will find the specific terms of any securities offered, and the
manner in which they are being offered, in supplements to this prospectus. You
should read this prospectus and any prospectus supplement carefully before you
invest.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.

The date of this prospectus is August 2, 2000.

<PAGE> 122

TABLE OF CONTENTS

<TABLE>
<S> <C>
About This Prospectus....................................... 2
Where You Can Find More Information......................... 2
Cautionary Statement About Forward-Looking Statements....... 3
Our Company................................................. 4
Ratio Of Earnings To Fixed Charges.......................... 6
Use Of Proceeds............................................. 6
Description Of Debt Securities.............................. 7
Plan Of Distribution........................................ 16
Experts..................................................... 18
Validity Of The Securities.................................. 18
</TABLE>

<PAGE> 123

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the
Securities and Exchange Commission using the "shelf" registration process. Under
this shelf registration process, we may issue the debt securities described in
this prospectus in one or more offerings up to a total dollar amount of
$2,000,000,000 (or its equivalent in foreign currencies).

This prospectus constitutes part of a registration statement on Form S-3
filed with the SEC under the Securities Act of 1933. It omits some of the
information contained in the registration statement, and reference is made to
the registration statement for further information with respect to us and the
securities we are offering. Any statement contained in this prospectus
concerning the provisions of any document filed as an exhibit to the
registration statement or otherwise filed with the SEC is not necessarily
complete, and in each instance reference is made to the copy of the document
filed.

This prospectus provides you with a general description of the debt
securities that we may offer. Each time we sell debt securities, we will provide
a prospectus supplement that will contain specific information about the terms
of that offering and the debt securities to be sold. The prospectus supplement
may also add, update or change information contained in this prospectus. Any
statement that we make in this prospectus will be modified or superseded by any
inconsistent statement made by us in a prospectus supplement. The registration
statement filed with the SEC includes exhibits that provide more details about
the matters discussed in this prospectus. You should read this prospectus, the
related exhibits filed with the SEC and any prospectus supplement, together with
the additional information described under "Where You Can Find More
Information."

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a Form 10 for the registration of our member
interests pursuant to Section 12(g) of the Securities Exchange Act of 1934. As a
result, we are now required to comply with the informational requirements of the
Securities Exchange Act of 1934, and, accordingly, we will file annual,
quarterly and special reports, proxy statements and other information with the
SEC. Our SEC filings are available to the public over the Internet at the SEC's
web site at http://www.sec.gov. You may also read and copy any document we file
at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C.
20549. You may obtain information on the operation of the SEC's Public Reference
Room in Washington, D.C. by calling the SEC at 1-800-SEC-0330.

The SEC allows us to "incorporate by reference" the information we file
with it, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
an important part of this prospectus, and information that we file later with
the SEC will automatically update and supersede this information. We incorporate
by reference the document listed below and any future filings made with the SEC
under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934
until we sell all of the securities being registered or until we terminate this
registration statement:

- Our Form 10 filed with the SEC.

If you ask us by phone or in writing, we will give you a free copy of any
or all of the information incorporated by reference (other than exhibits, unless
they are specifically incorporated by reference). Please direct your request by
mail to Duke Energy Field Services, LLC, Attention: Vice President, Investor
Relations, 370 17th Street, Suite 900, Denver, Colorado 80202 or by telephone at
(303) 595-3331.

You should rely only on the information incorporated by reference or
provided in this prospectus or any prospectus supplement. We have not authorized
any other person to provide you with different information. If anyone provides
you with different or inconsistent information, you should not rely on it. We
are not making an offer to sell these securities in any jurisdiction where the
offer or sale is not permitted. You should not assume that the information in
this prospectus, any prospectus supplement or
2
<PAGE> 124

any document incorporated by reference is accurate as of any date other than the
date of those documents. Our business, financial condition, results of
operations and prospects may have changed since those dates.

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This prospectus contains or incorporates by reference statements that do
not directly or exclusively relate to historical facts. Such statements are
"forward-looking statements." You can typically identify forward-looking
statements by the use of forward-looking words, such as "may," "could,"
"project," "believe," "anticipate," "expect," "estimate," "potential," "plan,"
"forecast" and other similar words.

All statements other than statements of historical facts contained in this
prospectus, including statements regarding our future financial position,
business strategy, budgets, projected costs and plans and objectives of
management for future operations, are forward-looking statements.

The forward-looking statements in this prospectus reflect our intentions,
plans, expectations, assumptions and beliefs about future events and are subject
to risks, uncertainties and other factors, many of which are outside our
control. Important factors that could cause actual results to differ materially
from the expectations expressed or implied in the forward-looking statements
include known and unknown risks. Known risks include, but are not limited to the
following:

- volatility in the market demand for oil and natural gas and NGLs (which
directly affects our results of operations);

- demand for natural gas and natural gas liquids may not increase as
rapidly or as much as we expect;

- the timing and extent of changes in commodity prices and demand for our
services;

- competition for raw natural gas supply;

- integration of the Phillips and Duke Energy assets that comprise our
business;

- our ability to grow through acquisitions;

- our use of derivative financial instruments to hedge commodity and
interest rate risks;

- our ability to access the debt and equity markets during the periods
covered by the forward-looking statements, which will depend on general
market conditions and the credit ratings for our debt obligations;

- changes in laws and regulations, particularly with regard to taxes,
safety and protection of the environment or the increased regulation of
the gas gathering and processing industry;

- weather and other natural phenomena;

- industry changes, including the impact of consolidations, and changes in
competition; and

- our ability to obtain required approvals for construction or
modernization of gathering and processing facilities, and the timing of
production from such facilities, which are dependent on the issuance by
federal, state and municipal governments or agencies of building,
environmental and other permits, the availability of specialized
contractors and work force and prices of and demand for products.

In light of these risks, uncertainties and assumptions, the forward-looking
events referred to in this prospectus or in any prospectus supplement might not
occur or might occur to a different extent or at a different time than described
in this prospectus or in any prospectus supplement. We undertake no obligation
to update or revise our forward-looking statements, whether as a result of new
information, future events or otherwise.

3
<PAGE> 125

OUR COMPANY

Duke Energy Field Services, LLC is a new company that holds the combined
North American midstream natural gas gathering, processing, marketing and
natural gas liquids businesses of Duke Energy Corporation ("Duke Energy") and
Phillips Petroleum Company ("Phillips"). The transaction in which those
businesses were combined is referred to in this prospectus as the "Combination."
Our limited liability company agreement limits the scope of our business to the
midstream natural gas industry in the United States and Canada, the marketing of
natural gas liquids in Mexico and the transportation, marketing and storage of
other petroleum products, unless otherwise approved by our Board of Directors.

Unless the context otherwise requires, descriptions of assets, operations
and results in this prospectus give effect to the Combination and related
transactions, the transfer to us of additional midstream natural gas assets
acquired by Duke Energy or Phillips prior to the Combination and the transfer to
us of the general partner of TEPPCO Partners, L.P. In this prospectus, the terms
"we," "us" and "our" refer to Duke Energy Field Services, LLC and our
subsidiaries, giving effect to the Combination and related transactions.

The midstream natural gas industry is the link between the exploration and
production of raw natural gas and the delivery of its components to end-use
markets. We are involved in the two principal segments of the midstream natural
gas industry:

- natural gas gathering, processing, transportation, marketing and storage;
and

- natural gas liquids ("NGLs") fractionation, transportation, marketing and
trading.

- we gathered and/or transported an average of approximately 7.3 billion
cubic feet per day of raw natural gas;

- we produced an average of approximately 400,000 barrels per day of NGLs;
and

- we marketed and traded an average of approximately 486,000 barrels per
day of NGLs.

We gather raw natural gas through gathering systems located in seven major
natural gas producing regions: Permian Basin, Mid-Continent, East
Texas -- Austin Chalk -- North Louisiana, Onshore Gulf of Mexico, Rocky
Mountains, Offshore Gulf of Mexico and Western Canada. Our gathering systems
consist of approximately 57,000 miles of gathering pipe, with approximately
38,000 active connections to producing wells.

Our natural gas processing operations involve the separation of raw natural
gas gathered both by our gathering system and by third party systems into NGLs
and residue gas. We process the raw natural gas at our 70 owned and operated
plants and at 13 third-party operated facilities in which we hold an equity
interest.

The NGLs separated from the raw natural gas by our processing operations
are either sold and transported as "NGL raw mix" or further separated through a
process known as fractionation into their individual components (ethane,
propane, butanes and natural gasoline) and then sold as components. We
fractionate NGL raw mix at our 12 owned and operated processing facilities and
at two third-party operated fractionators in which we hold an equity interest.

We sell NGLs to a variety of customers ranging from large, multi-national
petrochemical and refining companies to small regional retail propane
distributors. Substantially all of our NGL sales are made at market-based
prices, including approximately 40% of our NGL production that is committed to
Phillips under an existing 15-year contract. We market approximately 370,000
barrels per day of our NGLs processed at our owned and operated facilities and
approximately 40,000 barrels per day of NGLs

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processed at third-party operated facilities and trade approximately 75,000
barrels per day of NGLs at market centers.

The residue gas that results from our processing is sold at market-based
prices to marketers or end users including large industrial customers and
natural gas and electric utilities serving individual consumers. We market
residue gas through our wholly owned gas marketing company. We also store
residue gas at our 8.5 billion cubic foot natural gas storage facility.

- receives approximately 14% of the cash distributed by TEPPCO to its
partners, which consists of 12% from the incentive cash distribution and
2% from the general partner interest; and

- under the incentive cash distribution provisions, receives 50% of any
increase in TEPPCO's per unit cash distributions.

Our principal executive offices are located at 370 17th Street, Suite 900,
Denver, Colorado 80202, and our telephone number is (303) 595-3331.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table contains our consolidated ratio of earnings to fixed
charges for the periods indicated. From a financial reporting perspective, we
are the successor to Duke Energy's North American midstream natural gas
business. The subsidiaries of Duke Energy that conducted this business were
contributed to us in March 2000 immediately prior to the Combination. For
periods prior to the Combination, Duke Energy Field Services, LLC and these
former subsidiaries of Duke Energy collectively are referred to in this
prospectus as the "Predecessor Company."

<TABLE>
<CAPTION>
PREDECESSOR COMPANY HISTORICAL
--------------------------------------------------------------
THREE
MONTHS
YEARS ENDED DECEMBER 31, ENDED
-------------------------------------------------- MARCH 31,
1995 1996 1997 1998 1999 2000
------- -------- -------- ------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
RATIO OF EARNINGS TO FIXED
CHARGES....................... 4.10 9.11 2.52 1.07 2.33 4.23
</TABLE>

For purposes of calculating the ratios of earnings to fixed charges: (1)
"earnings" means income before extraordinary changes plus income taxes and fixed
charges, and (2) "fixed charges" include interest on indebtedness, amortization
of deferred financing costs, and that portion of lease expense that is deemed to
be representative of an interest factor. The ratio includes amounts from our
company, all of our majority-owned subsidiaries and our proportionate share of
distributed amounts from 50% owned investments accounted for using the equity
method.

USE OF PROCEEDS

Unless the applicable prospectus supplement states otherwise, we will use
the net proceeds from the sale of the debt securities offered by this prospectus
and any prospectus supplement for general corporate purposes, which may include
repayment of indebtedness, capital expenditures, future acquisitions, advances
to subsidiaries and additions to our working capital. If we do not use the net
proceeds immediately, we may temporarily invest them in short-term
interest-bearing obligations or deposit them with banks.

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DESCRIPTION OF DEBT SECURITIES

Any debt securities issued using this prospectus ("Debt Securities") will
be our direct unsecured general obligations. The Debt Securities will be senior
debt securities.

The Debt Securities will be issued under an Indenture (the "Indenture")
between us and The Chase Manhattan Bank (the "Trustee").

The Debt Securities may be issued from time to time in one or more series.
The particular terms of each series that is offered by a prospectus supplement
will be described in the prospectus supplement.

We have summarized selected provisions of the Indenture below. The summary
is not complete. The form of the Indenture has been filed as an exhibit to the
registration statement, and you should read the Indenture for provisions that
may be important to you. Whenever we refer in this prospectus or in any
prospectus supplement to particular sections or defined terms of the Indenture,
such sections or defined terms are incorporated by reference herein or therein,
as applicable. Capitalized terms used in this summary have the meanings
specified in the Indenture.

GENERAL

The Indenture provides that Debt Securities in separate series may be
issued from time to time without limitation as to aggregate principal amount. We
may specify a maximum aggregate principal amount for the Debt Securities of any
series. We will determine the terms and conditions of the Debt Securities,
including the maturity, principal and interest, but those terms must be
consistent with the Indenture. Debt Securities of a series need not be issued at
the same time, bear interest at the same rate or mature on the same date.

Each series of Debt Securities will rank equally with every other series of
Debt Securities and with all of our other unsecured and unsubordinated debt.

A prospectus supplement relating to any series of Debt Securities being
offered will include specific terms related to the offering, including the price
or prices at which the Debt Securities to be offered will be issued. These terms
will include some or all of the following:

- the title of the Debt Securities;

- the total principal amount of the Debt Securities;

- the date or dates on which the principal of the Debt Securities will be
payable or the method for determining the date or dates, and any right
that we have to change the date on which principal is payable;

- the interest rate or rates of the Debt Securities, if any, or the method
for determining the rate or rates, and the date or dates from which
interest will accrue;

- any interest payment dates and the regular record date for the interest
payable on each interest payment date, if any;

- whether we may extend the interest payment periods and, if so, the terms
of the extension;

- the places where payments on the Debt Securities will be payable;

- whether we have the option to redeem the Debt Securities and, if so, the
terms of our redemption option;

- any obligation we have to redeem the Debt Securities through a sinking
fund or to purchase the Debt Securities through a purchase fund or at the
option of the holder;

- whether the Debt Securities are defeasible;

- the currency in which payments will be made if other than U.S. dollars,
and the manner of determining the equivalent of those amounts in U.S.
dollars;
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<PAGE> 129

- if payments may be made, at our election or at the holder's election, in
a currency other than that in which the Debt Securities are stated to be
payable, then the currency in which those payments may be made, the terms
and conditions of the election and the manner of determining those
amounts;

- the portion of the principal payable upon acceleration of maturity, if
other than the entire principal;

- whether the Debt Securities will be issuable as global securities and, if
so, the securities depositary;

- any index or formula used for determining principal, premium or interest;

- if the principal payable on the maturity date will not be determinable on
one or more dates prior to the maturity date, the amount which will be
deemed to be such principal amount or the manner of determining it;

- any addition to or change in the events of default in the Indenture;

- any addition to or change in the covenants in the Indenture; and

- any other terms of the Debt Securities not inconsistent with the
provisions of the Indenture.

Unless we state otherwise in the prospectus supplement, we will issue the
Debt Securities only in fully registered form, without coupons, and there will
be no service charge for any registration of transfer or exchange of the Debt
Securities. We may, however, require payment to cover any tax or other
governmental charge payable in connection with any transfer or exchange. Subject
to the terms of the Indenture and the limitations applicable to global
securities, Debt Securities may be transferred or exchanged at the corporate
trust office of the Trustee or at any other office or agency maintained by us
for such purpose.

The Debt Securities of each series will be issuable in denominations of
$1,000 and any integral multiples of $1,000, unless we state otherwise in the
prospectus supplement.

We may offer and sell Debt Securities, including original issue discount
Debt Securities, at a substantial discount below their principal amount. The
applicable prospectus supplement will describe special U.S. federal income tax
and any other considerations applicable to those securities. In addition, the
applicable prospectus supplement may describe certain special U.S. federal
income tax or other considerations, if any, applicable to any Debt Securities
that are denominated in a currency other than U.S. dollars.

RANKING

Each series of Debt Securities will be unsecured senior obligations and
will rank equally with every other series of Debt Securities and with all of our
other unsecured and unsubordinated debt. The Debt Securities will, however, be
effectively subordinated in right of payment to any secured indebtedness to the
extent of the value of the assets securing that indebtedness. Except as provided
in the Indenture or specified in any authorizing resolution or supplemental
indenture relating to a series of Debt Securities to be issued, the Indenture
will not limit the amount of additional indebtedness that may rank equally with
the Debt Securities or the amount of indebtedness, secured or otherwise, that
may be incurred or preferred stock that may be issued by any of our
subsidiaries.

GLOBAL SECURITIES

We may issue some or all of the Debt Securities as book-entry securities.
Any such book-entry securities will be represented by one or more fully
registered global certificates. We will register each global security with, or
on behalf of, a securities depositary identified in the applicable prospectus
supplement. Each global certificate will be deposited with the securities
depositary or its nominee or a custodian for the securities depositary.

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<PAGE> 130

As long as the securities depositary or its nominee is the registered
holder of a global security representing Debt Securities, that person will be
considered the sole owner and holder of the global security and the Debt
Securities it represents for all purposes. Except in limited circumstances,
owners of beneficial interests in a global security:

- may not have the global security or any Debt Securities it represents
registered in their names;

- may not receive or be entitled to receive physical delivery of
certificated Debt Securities in exchange for the global security; and

- will not be considered the owners or holders of the global security or
any Debt Securities it represents for any purposes under the Debt
Securities or the Indenture.

We will make all payments of principal and any premium and interest on a
global security to the securities depositary or its nominee as the holder of the
global security. The laws of some jurisdictions require that certain purchasers
of securities take physical delivery of securities in definitive form. These
laws may impair the ability to transfer beneficial interests in a global
security.

Ownership of beneficial interests in a global security will be limited to
institutions having accounts with the securities depositary or its nominee,
which are called "participants" in this discussion, and to persons that hold
beneficial interests through participants. When a global security representing
Debt Securities is issued, the securities depositary will credit on its
book-entry, registration and transfer system the principal amounts of Debt
Securities the global security represents to the accounts of its participants.
Ownership of beneficial interests in a global security will be shown only on,
and the transfer of those ownership interests will be effected only through,
records maintained by:

- the securities depositary, with respect to participants' interests; and

- any participant, with respect to interests the participant holds on
behalf of other persons.

Payments participants make to owners of beneficial interests held through
those participants will be the responsibility of those participants. The
securities depositary may from time to time adopt various policies and
procedures governing payments, transfers, exchanges and other matters relating
to beneficial interests in a global security. None of the following will have
any responsibility or liability for any aspect of the securities depositary's or
any participant's records relating to beneficial interests in a global security
representing Debt Securities, for payments made on account of those beneficial
interests or for maintaining, supervising or reviewing any records relating to
those beneficial interests:

- our company;

- the Trustee under the Indenture; or

- an agent of either our company or the Trustee.

REDEMPTION

Any provisions relating to the redemption of Debt Securities will be set
forth in the applicable prospectus supplement. Unless we state otherwise in the
applicable prospectus supplement, we may redeem Debt Securities only upon notice
mailed at least 30 but not more than 60 days before the date fixed for
redemption. Unless we state otherwise in the applicable prospectus supplement,
that notice may state that the redemption will be conditional upon the Trustee
or the paying agent receiving sufficient funds to pay the principal, premium and
interest on those Debt Securities on the date fixed for redemption and that if
the Trustee or the paying agent does not receive those funds, the redemption
notice will not apply, and we will not be required to redeem those Debt
Securities.

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We will not be required to:

- issue, register the transfer of, or exchange any Debt Securities of a
series during the period beginning 15 days before the date the notice is
mailed identifying the Debt Securities of that series that have been
selected for redemption; or

- register the transfer of, or exchange any Debt Security of that series
selected for redemption except the unredeemed portion of a Debt Security
being partially redeemed.

CONSOLIDATION, MERGER, CONVEYANCE OR TRANSFER

The Indenture provides that we may consolidate or merge with or into, or
convey or transfer all or substantially all of our properties and assets to,
another corporation or other entity. Any successor must, however, assume our
obligations under the Indenture and the Debt Securities, and we must deliver an
officers' certificate and an opinion of counsel to the Trustee that affirms
compliance with all conditions in the Indenture. When those conditions are
satisfied, the successor will succeed to and be substituted for us under the
Indenture, and we will be relieved of our obligations under the Indenture and
the Debt Securities.

EVENTS OF DEFAULT

Unless otherwise specified in the applicable prospectus supplement, each of
the following will constitute an event of default under the Indenture:

- failure to pay principal of or premium on any Debt Security of that
series when due;

- failure to pay when due any interest on any Debt Security of that series
that continues for 60 days; for this purpose, the date on which interest
is due is the date on which we are required to make payment following any
deferral of interest payments by us under the terms of Debt Securities
that permit such deferrals;

- failure to make any sinking fund payment when required for any Debt
Security of that series that continues for 60 days;

- failure to perform any covenant in the applicable Indenture (other than a
covenant expressly included solely for the benefit of other series) that
continues for 90 days after the Trustee or the holders of at least 33% of
the outstanding Debt Securities of that series give us written notice of
the default;

- certain events of bankruptcy, insolvency or reorganization affecting us;
and

- any other event of default that may be provided with respect to Debt
Securities of that series.

In the case of the fourth event of default listed above, the Trustee may
extend the grace period. In addition, if holders of a particular series have
given a notice of default, then holders of at least the same percentage of Debt
Securities of that series, together with the Trustee, may also extend the grace
period. The grace period will be automatically extended if we have initiated and
are diligently pursuing corrective action.

If an event of default with respect to Debt Securities of a series occurs
and is continuing, then the Trustee or the holders of at least 33% of the
outstanding Debt Securities of that series may declare the principal amount of
all Debt Securities of that series to be immediately due and payable. However,
that event of default will be considered waived at any time after the
declaration but before a judgment for payment of the money due has been
obtained, if:

- we have paid or deposited with the Trustee all overdue interest, the
principal and any premium due otherwise than by the declaration and any
interest on such amounts, and any interest on overdue

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<PAGE> 132

interest, to the extent legally permitted, in each case with respect to
that series, and all amounts due to the Trustee; and

- all events of default with respect to that series, other than the
nonpayment of the principal that became due solely by virtue of the
declaration, have been cured or waived.

The Trustee is under no obligation to exercise any of its rights or powers
at the request or direction of any holders of Debt Securities unless those
holders have offered the Trustee security or indemnity against the costs,
expenses and liabilities that it might incur as a result. The holders of a
majority in principal amount of the outstanding Debt Securities of any series
have, with certain exceptions, the right to direct the time, method and place of
conducting any proceedings for any remedy available to the Trustee or the
exercise of any power of the Trustee with respect to those Debt Securities. The
Trustee may withhold notice of any default, except a default in the payment of
principal or interest, from the holders of any series if the Trustee in good
faith considers it in the interest of the holders to do so.

The holder of any Debt Security will have an absolute and unconditional
right to receive payment of the principal, any premium and, within certain
limitations, any interest on that Debt Security on its maturity date or
redemption date and to enforce those payments.

If certain payments on a series of Debt Securities are insured by a
financial guaranty insurance policy or other policy, terms other than those that
are described in the preceding three paragraphs may apply to that series.

We will be required to furnish to the Trustee annually a statement by
certain of our officers to the effect that we are not in default under the
Indenture, or if there has been a default, specifying the default and its
status.

PAYMENTS; PAYING AGENT

The paying agent will pay the principal of any Debt Securities only if
those Debt Securities are surrendered to it. Unless we state otherwise in the
applicable prospectus supplement, the paying agent will pay interest on Debt
Securities, subject to such surrender, where applicable, at its office or, at
our option:

- by wire transfer to an account at a banking institution in the United
States that is designated in writing to the Trustee at least 16 days
prior to the date of payment by the person entitled to that interest; or

- by check mailed to the address of the person entitled to that interest as
that address appears in the security register for those Debt Securities.

Unless we state otherwise in the applicable prospectus supplement, the
Trustee will act as paying agent for that series of Debt Securities, and the
principal corporate trust office of the Trustee will be the office through which
the paying agent acts. We may, however, change or add paying agents or approve a
change in the office through which a paying agent acts.

Any money that we have paid to a paying agent for principal or interest on
any Debt Securities that remains unclaimed at the end of two years after that
principal or interest has become due will be repaid to us at our request. After
repayment to us, holders should look only to us for those payments.

NEGATIVE PLEDGE

While any of the Debt Securities remain outstanding, we will not, and will
not permit any Principal Subsidiary (as defined below) to, create, or permit to
be created or to exist, any mortgage, lien, pledge, security interest or other
encumbrance upon any Principal Property (as defined below) of ours or of a
Principal Subsidiary, or upon any shares of stock of any Principal Subsidiary,
whether such Principal Property is, or shares of stock are, owned on or acquired
after the date of the Indenture, to secure any of

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our indebtedness for borrowed money, unless the Debt Securities then outstanding
are equally and ratably secured for so long as any such indebtedness is so
secured.

The foregoing restriction does not apply with respect to, among other
things:

- purchase money mortgages, or other purchase money liens, pledges,
security interests or encumbrances upon property that we or any Principal
Subsidiary acquired after the date of the Indenture; mortgages, liens,
pledges, security interests or other encumbrances existing on any
property or shares of stock at the time we or any Principal Subsidiary
acquired it or them, including those which exist on any property or
shares of stock of an entity with which we or any Principal Subsidiary
are consolidated or merged or which transfers or leases all or
substantially all of its properties to us or any Principal Subsidiary; or
conditional sales agreements or other title retention agreements and
leases in the nature of title retention agreements with respect to any
property that we or any Principal Subsidiary acquired after the date of
the Indenture; provided, however, that no such mortgage, lien, pledge,
security interest or other encumbrance shall extend to or cover any other
property that we or any Principal Subsidiary owns.

- mortgages, liens, pledges, security interests or other encumbrances upon
any of our property or the property of any Principal Subsidiary or shares
of stock of any Principal Subsidiary that existed on the date of the
initial issuance of Debt Securities or upon the property or shares of
stock of any corporation existing at the time that entity became a
Principal Subsidiary;

- pledges or deposits to secure performance in connection with bids,
tenders, contracts (other than contracts for the payment of money) or
leases to which we are, or any Principal Subsidiary is, a party;

- liens created by or resulting from any litigation or proceeding which at
the time is being contested in good faith by appropriate proceedings;

- liens incurred in connection with repurchase, swap or other similar
agreements (including commodity price, currency exchange and interest
rate protection agreements);

- mortgages, liens, pledges, security interests or other encumbrances on
any property arising in connection with any defeasance, covenant
defeasance or in-substance defeasance of our or any Principal
Subsidiary's indebtedness, including the Debt Securities;

- mortgages, liens, pledges, security interests or other encumbrances in
favor of the United States of America, any State, any foreign country or
any department, agency or instrumentality or political subdivision of any
such jurisdiction, to secure partial, progress, advance or other payments
pursuant to any contract or statute or to secure any indebtedness
incurred for the purpose of financing all or any part of the purchase
price or the cost of constructing or improving the property subject to
such mortgages, including, without limitation, mortgages to secure
indebtedness of the pollution control or industrial revenue bond type;

- indebtedness which may be issued by us or any of our Principal
Subsidiaries in connection with our consolidation or merger or the
consolidation or merger of any of our Principal Subsidiaries with or into
any other entity in exchange for or otherwise in substitution for secured
indebtedness of that entity ("Third Party Debt") which by its terms (1)
is secured by a mortgage on all or a portion of the property of that
entity, (2) prohibits secured indebtedness from being incurred by that
entity, unless the Third Party Debt is secured equally and ratably with
such secured indebtedness, or (3) prohibits secured indebtedness from
being incurred by that entity;

- indebtedness of any entity which we or any Principal Subsidiary are
required to assume in connection with a consolidation or merger of that
entity, with respect to which any of our or any Principal Subsidiary's
property is subjected to a mortgage, lien, pledge, security interest or
other encumbrance;

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- mortgages, liens, pledges, security interests or other encumbrances on
property held or used by us or any Principal Subsidiary in connection
with the gathering, processing, transportation or marketing of natural
gas, oil or other minerals;

- mortgages, liens, pledges, security interests or other encumbrances in
favor of us, one or more Principal Subsidiaries, one or more wholly owned
Subsidiaries (as defined below) or any of the foregoing in combination;

- mortgages, liens, pledges, security interests or other encumbrances upon
any property acquired, constructed, developed or improved by us or any
Principal Subsidiary after the date of the Indenture which are created
before, at the time of, or within 18 months after such acquisition (or in
the case of property constructed, developed or improved, after the
completion of the construction, development or improvement and
commencement of full commercial operation of that property, whichever is
later) to secure or provide for the payment of any part of its purchase
price or cost; provided that, in the case of such construction,
development or improvement, the mortgages, liens, pledges, security
interests or other encumbrances shall not apply to any property that we
or any Principal Subsidiary own other than real property that is
unimproved until that time; and

- the replacement, extension or renewal of any mortgage, lien, pledge,
security interest or other encumbrance described above or the
replacement, extension or renewal (not exceeding the principal amount of
indebtedness so secured together with any premium, interest, fee or
expense payable in connection with any such replacement, extension or
renewal) of the indebtedness so secured; provided that such replacement,
extension or renewal is limited to all or a part of the same property
that secured the mortgage, lien, pledge, security interest or other
encumbrance replaced, extended or renewed, plus improvements on it or
additions or accessions to it.

In addition, we or any Principal Subsidiary may create or assume any other
mortgage, lien, pledge, security interest or other encumbrance not excepted in
the Indenture without us equally and ratably securing the Debt Securities, if
immediately after that creation or assumption, our principal amount of
indebtedness for borrowed money that all such other mortgages, liens, pledges,
security interests and other encumbrances secure does not exceed an amount equal
to 10% of our Consolidated Adjusted Net Assets as shown on our consolidated
balance sheet for the accounting period occurring immediately before the
creation or assumption of that mortgage, lien, pledge, security interest or
other encumbrance.

For purposes of the preceding paragraphs, the following terms have these
meanings: "Principal Property" means any natural gas pipeline, natural gas
gathering system, natural gas storage facility, natural gas processing plant or
other plant or facility located in the United States that in the opinion of our
Board of Directors or our management is of material importance to our business
and the business of our consolidated subsidiaries taken as a whole; "Principal
Subsidiary" means any of our Subsidiaries that owns a Principal Property; and
"Subsidiary" means, as to any entity, an entity of which more than 50% of the
outstanding capital stock having ordinary voting power (other than capital stock
having such power only by reason of contingency) is at the time owned, directly
or indirectly, through one or more intermediaries, or both, by such entity.

LIMITATION ON SALES AND LEASEBACKS

Neither we nor any Principal Subsidiary may enter into any Sale and
Leaseback Transaction unless:

- we or that Principal Subsidiary would be entitled to incur indebtedness
in a principal amount equal to the Attributable Debt with respect to such
Sale and Leaseback Transaction, secured by a mortgage, lien, pledge,
security interest or other encumbrance on the property subject to such
Sale and Leaseback Transaction without equally and ratably securing the
Debt Securities pursuant to the covenant described above under "Negative
Pledge";

- after the date on which the Debt Securities are originally issued and
within a period beginning 12 months prior to the consummation of such
Sale and Leaseback Transaction and ending 12

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months after the consummation of such Sale and Leaseback Transaction, we
or any Subsidiary shall have expended for property used or to be used in
our business or the business our Subsidiaries an amount equal to all or a
portion of the net proceeds from such Sale and Leaseback Transaction and
we shall have elected to designate such amount as a credit against such
Sale and Leaseback Transaction (with any amount not being so designated
to be applied as set forth in the following bullet point);

- during the 12-month period after the effective date of such Sale and
Leaseback Transaction, we shall have applied to the voluntary defeasance
or retirement of Debt Securities or any other indebtedness an amount
equal to the greater of the net proceeds of the sale or transfer of the
property leased in such Sale and Leaseback Transaction and the fair
value, as determined by our Board of Directors, of such property at the
time such Sale and Leaseback Transaction was entered into (in either case
adjusted to reflect the remaining term of the lease and any amount we
expend as set forth in the preceding bullet point), less an amount equal
to the principal amount of such Debt Securities or other indebtedness
voluntarily defeased or retired within such 12-month period and not
designated as a credit against any other Sale and Leaseback Transaction
that we or any of our Subsidiaries enter into during such period; or

- such Sale and Leaseback Transaction is with one of our Affiliates.

This restriction will not apply to certain Sale and Leaseback Transactions
between us and a Principal Subsidiary or between Principal Subsidiaries.

For purposes of the preceding paragraph, the following terms have these
meanings: "Sale and Leaseback Transaction" means an arrangement with any lender
or investor or to which such lender or investor is a party providing for the
leasing for a term of greater than three years of any property or asset which
has been or is being sold or transferred more than 18 months after its
acquisition or the completion of construction or beginning of operation thereof
to such lender or investor or to any entity to whom funds have been or are to be
advanced by such lender or investor on the security of the property or asset;
"Affiliate" of a specified person or entity means any other person or entity
directly or indirectly controlling or controlled by or under direct or indirect
common control with such specified person or entity; "Attributable Debt" means
the total net amount of rent (discounted at the rate per year indicated in the
Indenture) required to be paid during the remaining term of any lease; and
"Consolidated Adjusted Net Assets" means the total amount of assets after
deducting:

- all current liabilities (excluding any which are by their terms
extendible or renewable at the option of the obligor to a time more than
12 months after the time as of which the amount is being computed); and

- total prepaid expenses and deferred charges.

MODIFICATION AND WAIVER

The Indenture may be modified with the consent of the holders of a majority
in principal amount of the outstanding Debt Securities of all series affected by
the modification (voting as one class). The consent of the holder of each
outstanding Debt Security affected is, however, required to:

- change the maturity date of the principal, or any installment of
principal or interest on that Debt Security;

- reduce the principal amount, the interest rate or any premium payable
upon redemption of that Debt Security;

- reduce the amount of principal due and payable upon acceleration of
maturity;

- change the currency of payment of principal, premium or interest on that
Debt Security;

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<PAGE> 136

- impair the right to institute suit to enforce any such payment on or
after the maturity date or redemption date;

- reduce the percentage in principal amount of Debt Securities of any
series required to amend or modify the Indenture, waive compliance with
certain restrictive provisions of the Indenture or waive certain
defaults; or

- with certain exceptions, modify the provisions of the Indenture governing
amendments of the Indenture or governing waiver of covenants or past
defaults.

In addition, we may supplement the Indenture to create new series of Debt
Securities and for certain other purposes, without the consent of any holders of
Debt Securities.

The holders of a majority in principal amount of the outstanding Debt
Securities of any series may waive, for that series, our compliance with certain
restrictive provisions of the Indenture, including the covenants described under
"Negative Pledge" and "Limitation on Sales and Leasebacks". The holders of a
majority in principal amount of the outstanding Debt Securities of all series
with respect to which a default has occurred and is continuing, voting as one
class, may waive that default for all those series, except a default in the
payment of principal or any premium or interest on any Debt Security or a
default with respect to a covenant or provision that cannot be amended or
modified without the consent of the holder of each outstanding Debt Security of
the series affected.

DEFEASANCE AND COVENANT DEFEASANCE

If, and to the extent, indicated in the applicable prospectus supplement,
we may elect, at our option at any time, to have the provisions of the Indenture
relating to defeasance or covenant defeasance applied to the Debt Securities of
any series or to any part of a series. The Indenture provides that we may be:

- discharged from our obligations, with certain limited exceptions, with
respect to any series of Debt Securities, as described in the Indentures,
such a discharge being called a "defeasance" in this prospectus; and

- released from our obligations under the covenants described in "Negative
Pledge" and "Limitations on Sales and Leasebacks" and any restrictive
covenants that may be especially established with respect to any series
of Debt Securities, such a release being called a "covenant defeasance"
in this prospectus.

We must satisfy certain conditions to effect a defeasance or covenant
defeasance. Those conditions include the irrevocable deposit with the Trustee,
in trust, of money or government obligations that through their scheduled
payments of principal and interest would provide sufficient money to pay the
principal and any premium and interest on those Debt Securities on the maturity
dates of those payments or upon redemption. Additional conditions, if any, to
exercising defeasance or covenant defeasance with respect to any series of Debt
Securities will be described in the applicable prospectus supplement.

Following a defeasance, payment of the Debt Securities defeased may not be
accelerated because of an event of default. Following a covenant defeasance, the
payment of Debt Securities may not be accelerated by reference to the covenants
from which we have been released. A defeasance may occur after a covenant
defeasance.

Under current U.S. federal income tax laws, a defeasance would be treated
as an exchange of the relevant Debt Securities in which holders of those Debt
Securities might recognize gain or loss. In addition, the amount, timing and
character of amounts that holders would thereafter be required to include in
income might be different from that which would be includible in the absence of
that defeasance. We

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urge investors to consult their own tax advisors as to the specific consequences
of a defeasance, including the applicability and effect of tax laws other than
U.S. federal income tax laws.

Under current U.S. federal income tax laws, unless accompanied by other
changes in the terms of the Debt Securities, a covenant defeasance should not be
treated as a taxable exchange.

CONCERNING THE TRUSTEE

The Trustee will perform only those duties that are specifically set forth
in the Indenture unless an event of default occurs and is continuing. In case an
event of default occurs and is continuing, the Trustee will exercise the same
degree of care as a prudent individual would exercise in the conduct of his or
her own affairs. Subject to those provisions, the Trustee is under no obligation
to exercise any of its powers under the Indenture at the request of any holder
of Debt Securities unless that holder offers reasonable indemnity to the Trustee
against the costs, expenses and liabilities that it might incur as a result.

NOTICE

Notice to holders of Debt Securities will be given by mail to such holders
as they may appear in the security register.

TITLE

We, the Trustee and any agent of our company or of the Trustee may treat
the person in whose name a Debt Security is registered as the absolute owner of
the Debt Security, whether or not such Debt Security may be overdue, for the
purpose of making payment and for all other purposes.

GOVERNING LAW

The Indenture and the Debt Securities will be governed by, and construed in
accordance with, the laws of the State of New York.

PLAN OF DISTRIBUTION

We may sell the Debt Securities:

- through underwriters or dealers;

- through agents;

- directly to a limited number of institutional purchasers or to a single
purchaser; or

- through a combination of any of these methods of sale.

The applicable prospectus supplement will describe the terms under which
the offered Debt Securities are offered, including:

- the names of any underwriters, dealers or agents;

- the purchase price and the net proceeds from the sale;

- any underwriting discounts and other items constituting underwriters'
compensation;

- any initial public offering price; and

- any discounts or concessions allowed, re-allowed or paid to dealers.

Any underwriters or dealers may from time to time change any initial public
offering price and any discounts or concessions allowed, re-allowed or paid to
dealers.

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If underwriters participate in the sale of the offered Debt Securities,
those underwriters will acquire the Debt Securities for their own account and
may resell them in one or more transactions, including negotiated transactions,
at a fixed public offering price or at varying prices determined at the time of
the sale. If the Debt Securities are sold through underwriters, the applicable
prospectus supplement will state the names and any compensation that may be paid
to the underwriters.

Unless we state otherwise in the applicable prospectus supplement, the
obligations of any underwriter to purchase the offered Debt Securities will be
subject to conditions, and the underwriter will be obligated to purchase all the
Debt Securities offered, except that in some cases involving a default by an
underwriter, less than all of the Debt Securities offered may be purchased.

If the offered Debt Securities are sold through an agent, the applicable
prospectus supplement will state the name and any compensation that may be paid
to the agent. Unless we state otherwise in the applicable prospectus supplement,
that agent will be acting on a best-efforts basis for the period of its
appointment.

We may have agreements with the underwriters, dealers and agents to
indemnify them against certain civil liabilities, including liabilities under
the Securities Act, or to contribute with respect to payments that the
underwriters, dealers or agents may be required to make.

Underwriters, dealers, agents and their affiliates may engage in
transactions with us or our affiliates, and may from time to time perform
services for us or our affiliates in the ordinary course of their business.

We may authorize agents, underwriters or dealers to solicit offers by
certain institutional investors to purchase offered Debt Securities providing
for payment and delivery on a future date specified in the applicable prospectus
supplement. Institutional investors to which such offers may be made, when
authorized, include commercial and savings banks, insurance companies, pension
funds, investment companies, education and charitable institutions and such
other institutions as may be approved by us. The obligations of any such
purchasers under such delayed delivery and payment arrangements will be subject
to the condition that the purchase of the offered Debt Securities will not at
the time of delivery be prohibited under applicable law. The underwriters and
such agents will not have any responsibility with respect to the validity or
performance of such contracts.

The Debt Securities may or may not be listed on a national securities
exchange.

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EXPERTS

The combined financial statements of Duke Energy Field Services, LLC and
Affiliates as of December 31, 1998 and 1999 and each of the three years in the
period ended December 31, 1999 and the 1997 combined statements of operations
and cash flows for UPFuels Division incorporated in this prospectus by reference
and appearing in the Form 10 of the Company filed on July 20, 2000 have been
audited by Deloitte & Touche LLP, independent auditors, as stated in their
reports which are also incorporated herein by reference, and have been so
incorporated in reliance upon the reports of such firm given upon their
authority as experts in accounting and auditing.

The consolidated financial statements of Phillips Gas Company as of
December 31, 1999 and 1998 and for each of the three years in the period ended
December 31, 1999 included in the Form 10 of the Company filed on July 20, 2000,
which are incorporated herein by reference, have been audited by Ernst & Young
LLP, independent auditors, as set forth in their report which is incorporated
herein by reference and has been so incorporated in reliance upon such report
given on the authority of such firm as experts in accounting and auditing.

The combined statements of income and cash flows of the UPFuels Division of
Union Pacific Resources Group, Inc. for the year ended December 31, 1998 and the
three months ended March 31, 1999 included in the Form 10 of the Company filed
on July 20, 2000, which are incorporated herein by reference, have been audited
by Arthur Andersen LLP, independent public accountants, as stated in their
report on such financial statements in reliance upon the report of such firm
given upon their authority as experts in auditing and accounting.

VALIDITY OF THE SECURITIES

Our legal counsel, Vinson & Elkins L.L.P., Houston, Texas, will pass upon
the validity of the Debt Securities on our behalf. Counsel named in any
applicable prospectus supplement will pass upon the validity of the Debt
Securities on behalf of any underwriters, dealers or agents.

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UNTIL , 2000, ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE
SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO
DELIVER A PROSPECTUS AND PROSPECTUS SUPPLEMENT. THIS IS IN ADDITION TO THE
DEALERS' OBLIGATION TO DELIVER A PROSPECTUS AND PROSPECTUS SUPPLEMENT WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.

[DUKE ENERGY FIELD SERVICES LOGO]

DUKE ENERGY FIELD SERVICES, LLC

$ % NOTES DUE
$ % NOTES DUE

------------------------------------------------------------
PROSPECTUS SUPPLEMENT
------------------------------------------------------------

MERRILL LYNCH & CO.

J.P. MORGAN & CO.
BANC OF AMERICA SECURITIES LLC
CHASE SECURITIES INC.
LEHMAN BROTHERS
MORGAN STANLEY DEAN WITTER

, 2000

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