DUKE ENERGY FIELD SERVICES CORP, S-1, 2000-03-15

DUKE ENERGY FIELD SERVICES CORP
S-1, 2000-03-15

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MARCH 15, 2000

REGISTRATION NO. 333-
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
---------------------
DUKE ENERGY FIELD SERVICES CORPORATION
(Exact name of registrant as specified in its charter)

<TABLE>
<CAPTION>
1321 DELAWARE 58-2511048
<S> <C> <C>
(Primary Standard Industrial (State or other jurisdiction of (I.R.S. Employer
Classification Code Number) incorporation or organization) Identification No.)
</TABLE>

370 17TH STREET
SUITE 900
DENVER, COLORADO 80202
(303) 595-3331
(Address, including zip code, and telephone number, including area code,
of registrant's principal executive offices)

DAVID D. FREDERICK
SENIOR VICE PRESIDENT
AND CHIEF FINANCIAL OFFICER
370 17TH STREET
SUITE 900
DENVER, COLORADO 80202
(303) 595-3331
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
---------------------
Copies to:

<TABLE>
<S> <C> <C>
JEFFERY B. FLOYD, ESQ. MARTHA B. WYRSCH, ESQ. ROBERT H. CRAFT, JR., ESQ.
VINSON & ELKINS L.L.P. DUKE ENERGY FIELD SERVICES SULLIVAN & CROMWELL
2300 FIRST CITY TOWER CORPORATION 1701 PENNSYLVANIA AVE., NW
1001 FANNIN STREET 370 17TH STREET, SUITE 900 WASHINGTON, D.C. 20004
HOUSTON, TEXAS 77002-6760 DENVER, COLORADO 80202 (202) 956-7500
(713) 758-2222 (303) 595-3331
</TABLE>

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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]

If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act of 1933, check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]

If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act of 1933, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]

If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act of 1933, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434
under the Securities Act of 1933, please check the following box. [ ]

CALCULATION OF REGISTRATION FEE

<TABLE>
<CAPTION>
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PROPOSED MAXIMUM
TITLE OF EACH CLASS OF SECURITIES TO BE REGISTERED AGGREGATE OFFERING PRICE(1) AMOUNT OF REGISTRATION FEE
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock, par value $.01 per share................ $800,000,000 $211,200
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</TABLE>

(1) Estimated solely for purposes of calculating the registration fee pursuant
to Rule 457(o) under the Securities Act of 1933.
---------------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
- --------------------------------------------------------------------------------
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<PAGE> 2

THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE
MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS
NOT AN OFFER TO SELL THESE SECURITIES AND WE ARE NOT SOLICITING OFFERS TO
BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.

PROSPECTUS (Subject to Completion)

Issued March 15, 2000

Duke Energy Field Services Corporation

COMMON STOCK

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

DUKE ENERGY FIELD SERVICES CORPORATION IS OFFERING SHARES OF ITS COMMON
STOCK. THIS IS OUR INITIAL PUBLIC OFFERING, AND NO PUBLIC MARKET CURRENTLY
EXISTS FOR OUR SHARES. WE ANTICIPATE THAT THE INITIAL PUBLIC OFFERING PRICE WILL
BE BETWEEN $ AND $ PER SHARE.

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

WE INTEND TO FILE AN APPLICATION FOR THE COMMON STOCK TO BE QUOTED ON THE NEW
YORK STOCK EXCHANGE UNDER THE SYMBOL "DEF."

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

INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON
PAGE 11.

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PRICE $ A SHARE

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

<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS COMPANY
-------- ------------- -----------
<S> <C> <C> <C>
Per Share....................... $ $ $
Total........................... $ $ $
</TABLE>

Duke Energy Field Services Corporation has granted the underwriters the right to
purchase up to an additional shares of common stock to cover
over-allotments.

The Securities and Exchange Commission and state securities regulators have not
approved or disapproved these securities or determined if this prospectus is
truthful or complete. Any representation to the contrary is a criminal offense.

Morgan Stanley & Co. Incorporated expects to deliver the shares of common stock
to purchasers on , 2000.

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

MORGAN STANLEY DEAN WITTER MERRILL LYNCH & CO.

BANC OF AMERICA SECURITIES LLC
LEHMAN BROTHERS
J.P. MORGAN & CO.
PAINEWEBBER INCORPORATED
PETRIE PARKMAN & CO.

, 2000
<PAGE> 3
ART/MAPS/DIAGRAMS

[The inside front cover will include a map of North America indicating the
location of our pipelines and plants.]
<PAGE> 4
OWNERSHIP OF OUR COMPANY

We are the issuer of the common stock offered by this prospectus and the
parent and owner of Duke Energy Field Services, LLC. On March , 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 Duke Energy Field
Services, LLC.

The following diagram is a summary of the ownership structure of our
company after giving effect to the U.S. and international common stock
offerings:

[CHART]

After the offerings, Duke Energy and Phillips will together hold % of the
outstanding common stock in our company. The exact allocation of these shares
between Duke Energy and Phillips will be determined based on the average of the
closing prices of our common stock on the New York Stock Exchange Composite Tape
on its first five trading days. Assuming that the five-day average equals the
estimated initial public offering price of $ per share, after the offerings
Duke Energy will indirectly own approximately % ( % if the underwriters
fully exercise their over-allotment option) and Phillips will indirectly own
approximately % ( % if the underwriters fully exercise their over-allotment
option) of our outstanding common stock. Although the exact allocation between
Duke Energy and Phillips may vary, upon completion of the offerings, Duke Energy
will, in any event, control our company through its share ownership and
representation on our Board of Directors. For a description of the combination
of the North American midstream natural gas businesses of Duke Energy and
Phillips, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- The Combination." For a description of the
relationships among Duke Energy, Phillips and our company, see "Relationship
with Duke Energy and Phillips."
<PAGE> 5

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
<S> <C>
Prospectus Summary.......................................... 3
Risk Factors................................................ 12
Cautionary Statement About Forward-Looking Statements....... 18
Use of Proceeds............................................. 19
Dividend Policy............................................. 19
Dilution.................................................... 20
Capitalization.............................................. 21
Selected Historical and Pro Forma Combined Financial and
Other Data................................................ 22
Five-Year Pro Forma Combined Financial and Other Data....... 24
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 25
Business.................................................... 36
Management.................................................. 55
Relationship with Duke Energy and Phillips.................. 61
Principal Stockholders...................................... 66
Description of Capital Stock................................ 67
Shares Eligible for Future Sale............................. 71
Material United States Federal Tax Consequences to
Non-United States Holders of
Common Stock.............................................. 72
Underwriters................................................ 75
Validity of the Common Stock................................ 77
Experts..................................................... 77
Additional Information...................................... 78
Index to Financial Statements............................... F-1
</TABLE>

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You should rely only on the information contained in this prospectus. We
have not authorized anyone to provide you with different information from that
contained in this prospectus. We are offering to sell shares of our common stock
and seeking offers to buy shares of our common stock only in jurisdictions where
offers and sales are permitted. The information contained in this prospectus is
accurate only as of the date of this prospectus or as of an earlier indicated
date, regardless of the date of delivery of this prospectus or of any sale of
our common stock. Our business, financial condition, results of operations and
prospects may have changed since those dates.

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

UNTIL , 2000, ALL DEALERS THAT BUY, SELL OR TRADE SHARES OF
COMMON STOCK, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO
DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE DEALERS' OBLIGATION TO DELIVER
A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD
ALLOTMENTS OR SUBSCRIPTIONS.

3
<PAGE> 6

PROSPECTUS SUMMARY

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

Duke Energy Field Services Corporation 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 and Phillips
Petroleum Company. The transaction in which those businesses were combined is
referred to in this prospectus as the "Combination." 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. 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, the terms "we," "us" and
"our" refer to Duke Energy Field Services Corporation and our subsidiaries,
including our principal subsidiary, Duke Energy Field Services, LLC (which we
refer to as "Field Services LLC") after the Combination and the other
transactions described above.

OUR COMPANY

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 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 are the largest gatherer of raw natural gas, based on wellhead volume,
and the largest producer of NGLs in North America. We are also one of the
largest marketers of NGLs in North America. In 1999:

- 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 $583.1
million of earnings before interest, taxes and depreciation and amortization
("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.

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 connections to active
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
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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 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 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 master 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. 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 (1) 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 (2) pursuant to the incentive cash
distribution provisions, receives 50% of any increase in TEPPCO's per unit cash
distributions.

OUR BUSINESS STRATEGY

We are the largest gatherer of raw natural gas and the largest producer and
one of the largest marketers of NGLs in North America. We have significant
midstream natural gas operations in five of the largest natural gas producing
regions in North America. To take advantage of the 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 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 also 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.

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, 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 were incorporated in the State of Delaware on December 8, 1999. Our
principal executive offices are located at 370 17th Street, Suite 900, Denver,
Colorado 80202, and our telephone number is (303) 595-3331.

6
<PAGE> 9

THE OFFERINGS

The following information does not include approximately shares of
common stock that may be issued upon the exercise of outstanding employee
options.

Common stock offered:

U.S. offering............ shares

International offering... shares

Total............ shares

Common stock to be
outstanding after the
offerings................ shares

Over-allotment option...... shares. Unless the context otherwise
requires, the information in this prospectus
assumes that the underwriters do not exercise the
over-allotment option.

Use of proceeds............ We expect the net proceeds to us from this sale of
common stock to be approximately $ million,
after deducting underwriting discounts and
estimated expenses of the offerings. We intend to
use the net proceeds from the offerings to repay
indebtedness incurred in connection with the
Combination.

Dividend policy............ We intend to declare and pay quarterly cash
dividends of $ per share, depending on our
financial results and action of our Board of
Directors. We expect the first dividend to be
payable with respect to the second quarter of 2000.

Proposed NYSE symbol....... "DEF"

RISK FACTORS

You should carefully read and consider all of the information included in
this prospectus. In particular, you should evaluate the specific factors
detailed under "Risk Factors" and "Cautionary Statement About Forward-Looking
Statements" before purchasing shares of our common stock.

7
<PAGE> 10

PRESENTATION OF FINANCIAL INFORMATION AND OTHER DATA

Duke Energy Field Services Corporation is a new company which 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 (1) 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 (2) what our future results of operations are likely to be.

HISTORICAL FINANCIAL INFORMATION 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 Corporation in December 1999 in contemplation of the Combination. Duke
Energy Field Services Corporation and these former subsidiaries of Duke Energy
collectively are referred to in this prospectus as the "Predecessor Company."
The historical financial statements and related financial and other data
included in this prospectus reflect the business of the Predecessor Company.
This historical financial information and other data should be viewed in light
of the following:

- the Combination is reflected as a March , 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 of the Predecessor Company do not
include the results of the general partner of TEPPCO.

For your additional information, we have also included the audited
financial statements of (1) the midstream natural gas business of Phillips that
was transferred to us in the Combination and (2) Union Pacific Fuels.

PRO FORMA FINANCIAL AND OTHER INFORMATION

In addition to the historical financial information and other data for the
Predecessor Company, this prospectus includes:

- unaudited pro forma financial statements of our company for 1999
reflecting (1) the Combination and the sale of our common stock in the
offerings, (2) the Predecessor Company's acquisition of Union Pacific
Fuels, (3) the transfer to us of additional midstream natural gas assets
acquired by Duke Energy or Phillips prior to consummation of the
Combination and (4) the transfer to us of the general partner of TEPPCO,
in each case as if the transactions had occurred on January 1, 1999 for
income statement purposes; and

- five-year pro forma combined financial and other data giving effect to
the Union Pacific Fuels acquisition and the Combination, as if each had
occurred on January 1, 1995.

8
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SUMMARY HISTORICAL AND PRO FORMA COMBINED
FINANCIAL AND OTHER DATA

The following table sets forth summary historical financial and other data
for the Predecessor Company. 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 is derived from unaudited
financial statements. In addition, the following table sets forth selected pro
forma financial and operating data, which reflect the historical results of
operations of the Predecessor Company, adjusted for (1) the acquisition of the
midstream natural gas business of Phillips in the Combination; (2) the
acquisition of Union Pacific Fuels; (3) 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;" (4) the offerings and the expected
application of the estimated proceeds; (5) the transfer to our company of
additional midstream natural gas assets acquired by Duke Energy or Phillips
prior to consummation of the Combination; and (6) the transfer to our company of
the general partner of TEPPCO; as if all had occurred as of January 1, 1999 for
income statement purposes and December 31, 1999 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.
The pro forma data set forth below are not necessarily indicative of results
that may occur in the future.

<TABLE>
<CAPTION>
PREDECESSOR COMPANY HISTORICAL PRO FORMA
------------------------------------------------------------ ----------
1995 1996 1997 1998 1999(1)(2) 1999(1)
-------- ---------- ---------- ---------- ---------- -------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Total operating revenues......... $805,188 $1,391,688 $1,801,832 $1,584,320 $3,458,310 $5,574,580
Total cost and expenses.......... 715,819 1,261,664 1,675,885 1,538,445 3,353,539 5,317,707
Earnings before interest and
tax............................ 91,029 133,021 135,731 57,720 127,273 284,211
Interest expense................. 20,115 12,747 51,113 52,403 52,915 159,092
Net income....................... 33,615 84,609 51,238 2,028 43,329 68,173

OTHER DATA:
EBITDA(3)........................ $128,310 $ 188,521 $ 203,432 $ 133,293 $ 258,061 556,828
Gas transported and/or processed
(TBtu/d)....................... 1.9 2.9 3.4 3.6 5.1 7.3
NGL production (MBbl/d).......... 55 79 108 110 192 400

MARKET DATA:
Average NGL price (per
gallon)(4)..................... $.29 $.39 $.35 $.26 $.34 $.33
Average natural gas price (per
MMBtu)(5)...................... $1.64 $2.59 $2.59 $2.11 $2.27 $2.27

BALANCE SHEET DATA (END OF PERIOD):
Total assets..................... $917,831 $1,459,416 $1,639,806 $1,770,838 $3,471,835 $6,275,143
Long-term debt................... $101,600 $ 101,600 $ 101,600 $ 101,600 $ 101,600 $ --(6)
</TABLE>

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(1) Includes $34 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 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. 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 included as a
supplemental disclosure because it may provide useful information regarding
our ability to service debt and to fund capital expenditures.

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(4) Based on index prices from the Mont Belvieu, Texas and Conway, Kansas market
hubs that are weighted by our component and location mix for the years
indicated.

(5) Based on the NYMEX Henry Hub prices for the years indicated.

(6) We expect to have $ billion of short-term indebtedness outstanding after
the offerings and expect to convert a significant portion of this short-term
debt to long-term debt as market conditions permit. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

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FIVE-YEAR PRO FORMA COMBINED FINANCIAL AND OTHER DATA

The following table sets forth five-year pro forma combined financial and
other data of our company. The pro forma combined financial and other data set
forth 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 ,
2000 and to the acquisition of Union Pacific Fuels, which occurred on March 31,
1999, as if each occurred on January 1, 1995.

The pro forma financial and other data set forth below should not be
considered to be indicative of (1) actual results that would have been realized
had the Combination and the acquisition of Union Pacific Fuels actually occurred
on January 1, 1995 or (2) 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.

<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <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
Costs of natural gas and petroleum
products................................. 1,729,278 2,976,059 3,798,465 3,527,533 4,554,776
Operating, maintenance, general and
administrative costs..................... 395,662 389,746 423,327 460,990 488,844
---------- ---------- ---------- ---------- ----------
Net margin(1).............................. $ 288,931 $ 632,468 $ 547,280 $ 314,174 $ 530,960
========== ========== ========== ========== ==========
OTHER DATA:
Gas transported and/or processed
(TBtu/d)................................. 5.4 6.5 7.5 7.3 7.3
NGLs production(MBbl/d).................... 277 313 358 373 400
MARKET DATA:
Average NGL price (per gallon)(2).......... $.28 $.38 $.34 $.25 $.33
Average natural gas (price per MMBtu)(3)... $1.64 $2.59 $2.59 $2.11 $2.27
</TABLE>

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(1) Net margin consists of income from continuing operations before interest
expense, income tax expense, equity in earnings of unconsolidated affiliates
and depreciation and amortization expense, less interest income. Net margin
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.

(2) 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.

(3) Based on the NYMEX Henry Hub prices for the years indicated.

11
<PAGE> 14

RISK FACTORS

Investing in our common stock will provide you with an equity ownership
interest in our company. As a stockholder, you will be subject to risks inherent
in our business. The performance of your shares will reflect the performance of
our business relative to, among other things, competition, market conditions and
general economic and industry conditions. The value of your investment may
increase or decrease and you could suffer a loss. You should carefully consider
the risks described below as well as the other information contained in this
prospectus. Additional risks currently not known to us or that we currently deem
immaterial may also impair our business operations.

RISKS RELATED TO OUR BUSINESS AND OPERATIONS

OUR BUSINESS IS DEPENDENT UPON PRICES AND MARKET DEMAND FOR OIL, NATURAL
GAS AND NGLS, WHICH ARE BEYOND OUR CONTROL AND HAVE BEEN EXTREMELY VOLATILE.

The markets and prices for our main products, residue gas and NGLs, depend
upon factors beyond our control. These factors include demand for oil, natural
gas and NGLs, which fluctuate with changes in market and economic conditions and
other factors, including:

- the impact of weather on the demand for oil and natural gas;

- the level of domestic oil and natural gas production;

- the availability of imported oil and natural gas;

- the availability of local, intrastate and interstate transportation
systems;

- the availability and marketing of competitive fuels;

- the impact of energy conservation efforts; and

- the extent of governmental regulation and taxation.

In the past, the prices of residue gas and NGLs have been extremely volatile and
we expect this volatility to continue. Reductions in demand and decreases in
prices for residue gas or NGLs likely would result in decreased revenues and
adversely affect operating income.

WE MUST CONTINUALLY COMPETE FOR RAW NATURAL GAS SUPPLY, AND OUR SUCCESS
DEPENDS UPON THE AVAILABLE SUPPLY OF RAW NATURAL GAS.

In order to maintain or increase throughput levels in our raw natural gas
gathering systems and asset utilization rates at our processing plants, we must
continually contract for new raw natural gas supplies to offset natural declines
in connected supplies of raw natural gas. Our future growth will depend, in
part, upon whether we can contract for additional supplies at a greater rate
than the rate of natural decline in our currently connected supplies. The
primary factors affecting our ability to connect new wells to our gathering
facilities include our success in contracting for existing producing raw natural
gas supplies that are not committed to other systems and the level of drilling
activity near our gathering systems. Drilling activity generally increases (or
decreases) as oil and natural gas prices increase (or decrease). Our industry is
highly competitive, and we cannot assure you that we will be able to obtain
additional contracts for raw natural gas supplies.

Our results are materially affected by the volume of raw natural gas
processed at our facilities and asset utilization rates. Fluctuations in energy
prices can greatly affect production rates and investments by third parties in
the development of new oil and natural gas reserves. A material decrease in
natural gas production for a prolonged period in the areas where our gathering
facilities are located, as a result of depressed commodity prices or otherwise,
likely would have a material adverse effect on our results of operations and
financial position.

12
<PAGE> 15

BECAUSE WE ARE A NEWLY COMBINED COMPANY WITH NO COMBINED OPERATING HISTORY,
NEITHER OUR HISTORICAL NOR OUR PRO FORMA FINANCIAL AND OPERATING DATA MAY BE
REPRESENTATIVE OF OUR FUTURE RESULTS.

We are a newly combined company with no combined operating history. Our
lack of a combined operating history may make it difficult to forecast our
future operating results. Our historical financial statements included in this
prospectus reflect the historical results of operations, financial position and
cash flows of the midstream natural gas businesses of Duke Energy prior to the
Combination. The unaudited pro forma financial information included in this
prospectus are based on the two separate midstream businesses of Duke Energy and
Phillips prior to the Combination, each of which were managed separately prior
to the Combination. As a result, the historical and pro forma information may
not give you an accurate indication of what our actual results would have been
if the Combination had been completed at the beginning of the periods presented
or of what our future results of operations are likely to be. In addition, our
future results will depend on our ability to integrate our operations,
efficiently manage our combined facilities and execute our business strategy.

A SIGNIFICANT COMPONENT OF OUR GROWTH STRATEGY IS ACQUISITIONS, AND WE MAY
NOT BE ABLE TO COMPLETE FUTURE ACQUISITIONS SUCCESSFULLY.

Our business strategy has emphasized growth through strategic acquisitions,
but we cannot assure you that we will be able to continue to identify attractive
or willing acquisition candidates or that we will be able to acquire these
candidates on economically acceptable terms. Competition for acquisition
opportunities in our industry exists and may increase. Any increase in the level
of competition for acquisitions may increase the cost of, or cause us to refrain
from, completing acquisitions.

Our strategy of completing acquisitions is dependent upon, among other
things, our ability to obtain debt and equity financing and regulatory
approvals. Our ability to pursue our growth strategy may be hindered if we are
not able to obtain financing or regulatory approvals, including those under
federal and state antitrust laws. Our ability to grow through acquisitions and
manage such growth will require us to continue to invest in operational,
financial and management information systems and to attract, retain, motivate
and effectively manage our employees. The inability to manage the integration of
acquisitions effectively could have a material adverse effect on our financial
condition, results of operations and business. Pursuit of our acquisition
strategy may cause our financial position and results of operations to fluctuate
significantly from period to period.

GROWING OUR BUSINESS BY CONSTRUCTING NEW PIPELINES AND PROCESSING
FACILITIES SUBJECTS US TO CONSTRUCTION RISKS AND RISKS THAT RAW NATURAL GAS
SUPPLIES WILL NOT BE AVAILABLE UPON COMPLETION OF THE FACILITIES.

One of the ways we intend to grow our business is through the construction
of additions to our existing gathering systems and construction of new
processing facilities. The construction of gathering and processing facilities
requires the expenditure of significant amounts of capital, which may exceed our
expectations. Generally, we may have only limited raw natural gas supplies
committed to these facilities prior to their construction. Moreover, we may
construct facilities to capture anticipated future growth in production in a
region in which anticipated production growth does not materialize. As a result,
there is the risk that new facilities may not be able to attract enough raw
natural gas to achieve our expected investment return, which could adversely
affect our results of operations and financial condition.

WE OPERATE IN HIGHLY COMPETITIVE MARKETS IN COMPETITION WITH A NUMBER OF
DIFFERENT COMPANIES.

We face strong competition in our geographic areas of operations. Our
competitors include major integrated oil companies, interstate and intrastate
pipelines and raw natural gas gatherers and processors. Some of our competitors
offer more services or have greater financial resources and access to larger raw
natural gas supplies than we do. We compete with integrated companies that have
greater access to raw natural gas supply and are less susceptible to
fluctuations in price or volume, and some of our competitors that have greater
financial resources may have an advantage in competing for acquisitions or other
new business opportunities.

13
<PAGE> 16

FEDERAL, STATE OR LOCAL REGULATORY MEASURES COULD ADVERSELY AFFECT OUR
BUSINESS.

While the Federal Energy Regulatory Commission, or FERC, does not directly
regulate the major portions of our operations, federal regulation, directly or
indirectly, influences certain aspects of our business and the market for our
products. As a raw natural gas gatherer and not an operator of interstate
transmission pipelines, we generally are exempt from FERC regulation under the
Natural Gas Act of 1938, but FERC regulation still significantly affects our
business. In recent years, FERC has pursued pro-competition policies in its
regulation of interstate natural gas pipelines. However, we cannot assure you
that FERC will continue this approach as it considers proposals by pipelines to
allow negotiated rates not limited by rate ceilings, pipeline rate case
proposals and revisions to rules and policies that may affect rights of access
to natural gas transportation capacity.

While state public utility commissions do not regulate our business, state
and local regulations do affect our business. We are subject to ratable take and
common purchaser statutes in the states where we operate. Federal law leaves any
economic regulation of raw natural gas gathering to the states, and some of the
states in which we operate have adopted complaint-based or other limited
economic regulation of raw natural gas gathering activities. The states in which
we conduct operations administer federal pipeline safety standards under the
Pipeline Safety Act of 1968, and the "rural gathering exemption" under that
statute that our gathering facilities currently enjoy may be restricted in the
future. See "Business -- Regulation."

OUR BUSINESS INVOLVES HAZARDOUS SUBSTANCES AND MAY BE ADVERSELY AFFECTED BY
ENVIRONMENTAL REGULATION.

Many of the operations and activities of our gathering systems, plants and
other facilities are subject to significant federal, state and local
environmental laws and regulations. These include, for example, laws and
regulations that impose obligations related to air emissions and discharge of
wastes from our facilities and the clean up of hazardous substances that may
have been released at properties currently or previously owned or operated by us
or locations to which we have sent wastes for disposal. Various governmental
authorities have the power to enforce compliance with these regulations and the
permits issued pursuant to them, and violators are subject to administrative,
civil and criminal penalties, including civil fines, injunctions or both.
Liability may be incurred without regard to fault for the remediation of
contaminated areas. Private parties, including the owners of properties through
which our gathering systems pass, may also have the right to pursue legal
actions to enforce compliance as well as to seek damages for non-compliance with
environmental laws and regulations or for personal injury or property damage.

There is inherent risk of the incurrence of environmental costs and
liabilities in our business due to our handling of natural gas and other
petroleum products, air emissions related to our operations, historical industry
operations, waste disposal practices and the prior use of natural gas flow
meters containing mercury. In addition, the possibility exists that stricter
laws, regulations or enforcement policies could significantly increase our
compliance costs and the cost of any remediation that may become necessary. We
cannot assure you that we will not incur material environmental costs and
liabilities. Furthermore, we cannot assure you that our insurance will provide
sufficient coverage in the event an environmental claim is made against us.

Our business may be adversely affected by increased costs due to stricter
pollution control requirements or liabilities resulting from non-compliance with
required operating or other regulatory permits. New environmental regulations
might adversely affect our products and activities, including processing,
storage and transportation, as well as waste management and air emissions.
Federal and state agencies also could impose additional safety requirements, any
of which could affect our profitability.

OUR BUSINESS INVOLVES MANY HAZARDS AND OPERATIONAL RISKS, SOME OF WHICH MAY
NOT BE COVERED BY INSURANCE.

Our operations are subject to the many hazards inherent in the gathering,
compressing, treating and processing of raw natural gas and NGLs and storage of
residue gas, including ruptures, leaks and fires. These risks could result in
substantial losses due to personal injury and/or loss of life, severe damage to
and destruction of property and equipment and pollution or other environmental
damage and may result in curtailment or suspension of our related operations. We
are not fully insured against all risks incident to our

14
<PAGE> 17

business. If a significant accident or event occurs that is not fully insured,
it could adversely affect our operations and financial condition. See
"Business -- Insurance."

OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL
LOSSES OR REDUCE OUR INCOME.

We use futures and option contracts traded on the New York Mercantile
Exchange and over-the-counter options and price and basis swaps with other
natural gas merchants and financial institutions. Use of these instruments is
intended to reduce our exposure to short-term volatility in commodity prices. We
could, however, incur financial losses or fail to recognize the full value of a
market opportunity as a result of volatility in the market values of the
underlying commodities or if one of our counterparties fails to perform under a
contract. For additional information about our risk management activities,
including our use of derivative financial instruments, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Qualitative and Quantitative Disclosure about Market Risk."

OUR SUCCESS DEPENDS ON KEY MEMBERS OF OUR MANAGEMENT, THE LOSS OF WHOM
COULD DISRUPT OUR BUSINESS OPERATIONS.

We depend on the continued employment and performance of key management
personnel. We have entered into employment agreements with some of our executive
officers. If our key managers resign or become unable to continue in their
present roles and are not adequately replaced, our business operations could be
materially adversely affected. We do not maintain any "key man" life insurance
for any officers. See "Management."

RISKS RELATED TO OUR RELATIONSHIP WITH DUKE ENERGY AND PHILLIPS

DUKE ENERGY AND PHILLIPS WILL CONTROL THE OUTCOME OF STOCKHOLDER VOTING AND
MAY EXERCISE THEIR VOTING POWER IN A MANNER ADVERSE TO YOU.

Accordingly, Duke Energy and Phillips are in a position to control the
outcome of matters requiring a stockholder vote, including the election of
directors, adoption of an amendment to our certificate of incorporation or
bylaws or approving transactions involving a change of control. In addition, our
certificate of incorporation grants each of Duke Energy and Phillips the right
to purchase shares of common stock in our future public offerings in an amount
sufficient to maintain its percentage ownership in our company so long as each
owns at least 20% of our common stock.

Duke Energy and Phillips have agreed to vote their shares of common stock
in a manner that ensures that seven designees of Duke Energy (two of whom are
required to be independent directors) and four designees of Phillips (one of
whom is required to be an independent director) are elected to our Board of
Directors. Our bylaws require the approval of at least eight of our 11 directors
for authorization of a variety of corporate actions, including significant
acquisitions, dispositions, capital expenditures and borrowings. As a result,
Duke Energy and Phillips have the ability to control our policies, management
and affairs, including decisions regarding the acquisition or disposition of
assets, business combinations, issuances of common stock and the declaration of
dividends. For example, Duke Energy and Phillips could prevent transactions that
would dilute their respective ownership interests in our company, including
prospective acquisitions that we would finance by issuing shares of our common
stock. The interests of Duke Energy and Phillips may differ from yours, and they
may vote their common stock in a manner that may adversely affect you.
15
<PAGE> 18

SEVERAL OF OUR DIRECTORS AND OFFICERS MAY HAVE CONFLICTS OF INTEREST
BECAUSE THEY ARE ALSO DIRECTORS OR OFFICERS OF DUKE ENERGY, PHILLIPS OR THE
GENERAL PARTNER OF TEPPCO.

After completion of the offerings, five of our directors also will be past
or current directors or officers of Duke Energy, three will be past or current
directors or officers of Phillips and two will be directors of the general
partner of TEPPCO, a situation that may create conflicts of interest. These
directors and officers have dual responsibilities. Directors and officers of
Duke Energy and Phillips have fiduciary duties to manage Duke Energy and
Phillips, including their investments in subsidiaries and affiliates such as us,
in a manner beneficial to Duke Energy and Phillips and their stockholders.
Directors and officers of the general partner of TEPPCO have fiduciary duties to
manage the business of TEPPCO in a manner beneficial to TEPPCO and its
unitholders, including its public unitholders. As directors and officers of our
company, they also have fiduciary duties to manage us in a manner beneficial to
us and our stockholders. Their duties as directors or officers of Duke Energy,
Phillips or the general partner of TEPPCO may conflict with their duties as
directors of our company with respect to corporate opportunities, business
dealings among Duke Energy, Phillips, TEPPCO and us and other corporate matters.
For example, Duke Energy, Phillips, TEPPCO and our company are engaged in
related lines of business, and we may have similar acquisition strategies. As a
result, conflicts may arise because acquisition opportunities that may be
beneficial to more than one company may be presented to our officers or
directors who are also officers or directors of Duke Energy, Phillips or the
general partner of TEPPCO. Other conflicts of interest may arise in the future
as a result of the extensive relationships among our company, Duke Energy,
Phillips and TEPPCO. The resolution of these conflicts may not always be in our
or our stockholders' best interest.

OUR BUSINESS OPPORTUNITIES COULD BE LIMITED BECAUSE DUKE ENERGY, PHILLIPS
AND THEIR RESPECTIVE AFFILIATES MAY COMPETE WITH US IN MIDSTREAM NATURAL GAS
ACTIVITIES, AND WE MAY ONLY ENGAGE IN THE LIMITED ACTIVITIES DESCRIBED IN THIS
PROSPECTUS.

Our certificate of incorporation limits the scope of our business to the
midstream natural gas industry in the United States and Canada and the marketing
of NGLs in Mexico and does not permit us to pursue other potentially profitable
activities. Duke Energy and its affiliates are permitted to engage in the
midstream natural gas industry and related businesses, even if it has a negative
competitive effect on us. We cannot amend these provisions of our certificate of
incorporation without Duke Energy's prior consent, which Duke Energy may
withhold at its sole discretion. Phillips also has retained midstream natural
gas assets in its exploration and production organization and is permitted to
engage in the midstream natural gas industry and related businesses, even if it
has a negative competitive effect on our company.

DUKE ENERGY'S OWNERSHIP INTEREST AND PROVISIONS CONTAINED IN OUR
CERTIFICATE OF INCORPORATION COULD DISCOURAGE A TAKEOVER ATTEMPT, WHICH MAY
REDUCE OR ELIMINATE THE LIKELIHOOD OF A CHANGE OF CONTROL TRANSACTION AND,
THEREFORE, YOUR ABILITY TO SELL YOUR SHARES FOR A PREMIUM.

In addition to Duke Energy's controlling position, provisions contained in
our certificate of incorporation, such as limitations on stockholder proposals
at meetings of stockholders and the inability of stockholders to call special
meetings, could make it more difficult for a third party to acquire control of
our Company, even if some of our stockholders considered such a change of
control to be beneficial. Our certificate of incorporation also authorizes our
Board of Directors to issue preferred stock without stockholder approval. If our
Board of Directors elects to issue preferred stock, it could make it even more
difficult for a third party to acquire us, which may reduce or eliminate your
ability to sell your shares of common stock at a premium. See "Description of
Capital Stock."

OUR COSTS RELATED TO CORPORATE SERVICES COULD INCREASE AS OUR RELATIONSHIP
WITH DUKE ENERGY OR PHILLIPS CHANGES IN THE FUTURE.

We have entered into agreements with Duke Energy and Phillips under which
Duke Energy and Phillips provide corporate support services to us. Our
agreements with Duke Energy and Phillips expire, unless extended, on December
31, 2000. Replacing such services, either internally or through third-party
providers, may cause disruptions in our operations or result in costs in excess
of our historical costs for similar services.

16
<PAGE> 19

PHILLIPS HAS NOT YET COMPLETELY TRANSFERRED TO US RECORD TITLE TO ALL OF
ITS MIDSTREAM ASSETS THAT WERE TRANSFERRED TO US IN THE COMBINATION. IN THE
EVENT OF A BANKRUPTCY OF PHILLIPS, WE MAY NOT BE ABLE TO OBTAIN RECORD TITLE TO
THESE ASSETS.

Although Phillips has transferred to us the midstream natural gas assets it
contributed in the Combination, Phillips and its affiliates continue to hold
record title to some of the real property for our benefit. Although Phillips is
in the process of transferring record title to us, the process may not be
completed for some time. In the event of a Phillips bankruptcy before record
title has been conveyed to us, we may have difficulty or be unable to obtain
record title to these properties. The failure to complete this planned record
title transfer could have a material adverse effect on our business, operations
and financial results.

RISKS RELATED TO OWNERSHIP OF OUR COMMON STOCK

THERE HAS BEEN NO PRIOR PUBLIC MARKET FOR OUR COMMON STOCK, AND THE PRICE
OF OUR STOCK MAY BE SUBJECT TO FLUCTUATIONS.

No market for our common stock existed prior to this offering, and although
we have applied to have our shares of common stock listed on the New York Stock
Exchange, we cannot assure you that a viable trading market for our common stock
will develop or be sustained.

The initial public offering price was determined by negotiations among us,
Duke Energy and the underwriters based on numerous factors. The market price of
our common stock after this offering may vary from the initial public offering
price, and you may not be able to resell your shares at or above the initial
public offering price. The market price of our common stock is likely to be
volatile and could be subject to fluctuations in response to factors such as the
following, most of which are beyond our control:

- operating results that vary from the expectations of securities analysts
and investors;

- changes in expectations as to our future financial performance, including
financial estimates by securities analysts and investors;

- the operations, regulatory, market and other risks discussed in this
section;

- announcements by us or our competitors of significant contracts,
acquisitions, strategic partnerships, joint ventures or capital
commitments;

- announcements by third parties of significant claims or proceedings
against us; and

- future sales of our common stock.

In addition, the stock market has from time to time experienced extreme price
and volume fluctuations. These broad market fluctuations may adversely affect
the market price of our common stock.

FUTURE SALES OF OUR COMMON STOCK BY EXISTING STOCKHOLDERS COULD DEPRESS OUR
STOCK PRICE.

Sales of a substantial number of shares of our common stock after the
offerings could adversely affect the market price of our common stock by
introducing a significant increase in the supply of common stock to the market.
This increased supply could cause the market price of our common stock to
decline significantly.

After the offerings, we will have outstanding shares of common stock,
and we will have reserved an additional shares of common stock for
issuance under our 2000 Long-Term Incentive Plan. All the shares of common stock
sold in the offerings will be freely tradable without restriction or further
registration under the federal securities laws unless purchased by one of our
"affiliates," as that term is defined in Rule 144 under the Securities Act of
1933. The remaining shares of outstanding common stock, including shares held by
Duke Energy, Phillips and their affiliates, will be "restricted securities"
under the Securities Act and will be subject to restrictions on the timing,
manner and volume of sales of restricted shares.

In connection with the offerings, we and our officers and directors, as
well as Duke Energy and Phillips, have agreed, with exceptions specified in the
lock-up agreements, not to sell any shares of common stock for a period of 180
days after the date of this prospectus without the prior written consent of
Morgan Stanley & Co.
17
<PAGE> 20

Incorporated. Upon expiration of the lock-up period, the shares outstanding and
owned by Duke Energy, Phillips and their affiliates may be sold in the future
without registration under the Securities Act to the extent permitted by Rule
144 or any applicable exemption under the Securities Act. Pursuant to a
registration rights agreement between our company, Duke Energy and Phillips,
Duke Energy, Phillips and their affiliates have the right to require us to
register their shares of our common stock following the lock-up period. The
possibility that Duke Energy, Phillips or any of their or our affiliates may
dispose of shares of our common stock, or the announcement or completion of any
such transaction, could have an adverse effect on the market price of our common
stock. See "Shares Eligible for Future Sale."

YOU WILL EXPERIENCE IMMEDIATE AND SUBSTANTIAL DILUTION.

The initial public offering price is substantially higher than our
pre-offering net tangible book value per share of our common stock. Purchasers
of our common stock in the offerings will experience immediate and substantial
dilution. The dilution will be approximately $ per share in net tangible
book value of our common stock from the initial public offering price. If
outstanding options to purchase shares of our common stock are exercised, there
will be further dilution. See "Dilution" and "Management" for information
regarding outstanding stock options and additional stock options that may be
granted.

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This prospectus contains statements that do not directly or exclusively
relate to historical facts. Such statements are "forward-looking statements"
within the meaning of the Private Securities Litigation Reform Act of 1995. 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,
those listed in the "Risk Factors" section and elsewhere in this prospectus as
well as:

- our ability to access the debt and equity markets, which will depend on
general market conditions and our 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 gathering end processing industry;

- the timing and extent of changes in commodity prices and demand for our
services;

- 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 thereof, 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 events
described in the forward-looking statements in this prospectus might not occur
or might occur to a different extent or at a different time than

18
<PAGE> 21

described in this prospectus. We undertake no obligation to update or revise our
forward-looking statements, whether as a result of new information, future
events or otherwise.

USE OF PROCEEDS

We expect the net proceeds to us from the offerings to be approximately
$ million ($ million if the underwriters fully exercise their
over-allotment option), after deducting underwriting discounts and after
commissions and estimated offering expenses of $ .

We intend to use the net proceeds that we receive from the offerings to
repay outstanding commercial paper. The proceeds of the commercial paper were
used to make one-time cash distributions of approximately $1.5 billion to Duke
Energy and approximately $1.2 billion to Phillips and for expenses incurred in
connection with the Combination. At March , 2000, our outstanding commercial
paper had maturity dates ranging from days to days, with annual interest
rates ranging from % to %. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- The Combination" and
"-- Liquidity and Capital Resources."

DIVIDEND POLICY

Following consummation of the offerings, we currently anticipate paying
quarterly cash dividends on our common stock. Subject to attaining earnings
sufficient to pay such dividends and meet our other cash needs, our Board of
Directors currently intends to declare and pay an initial quarterly dividend of
$ per share of common stock payable , 2000 to holders of
record on , 2000. We expect cash flow from operations to be
sufficient to fund this dividend. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."

The declaration, amount and payment of dividends are at the discretion of
our Board of Directors and will depend upon our results of operations, financial
condition, cash requirements for our business, future prospects and other
factors determined to be relevant by our Board of Directors, as well as the
effect of any restrictive covenants in our credit agreements and debt
instruments. We cannot assure you that dividends will be paid in the future nor
can we assure you as to the amount of any dividends.

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<PAGE> 22
DILUTION

If you invest in our common stock, your interest will be diluted to the
extent of the difference between the public offering price per share of our
common stock and the net tangible book value per share of our common stock after
the offerings. We calculate net book value per share by dividing the net assets
(total assets less liabilities) by the number of shares outstanding before the
offerings. We calculate net tangible book value per share by dividing the net
tangible assets (total assets less liabilities and net intangible assets) by the
number of shares of common stock outstanding before the offerings.

Our pro forma net book value and pro forma net tangible book value as of
December 31, 1999 (giving effect to the Combination as if it had occurred on
December 31, 1999) were approximately $ and $ per share, respectively.
Without taking into account any changes in pro forma net book value or net
tangible book value after December 31, 1999, other than to give effect to the
offerings (at an assumed initial public offering price per share of $ ) and
the application of the estimated net proceeds from the offerings, the pro forma
net book value of the common stock as of December 31, 1999 would have been
approximately $ million, or $ per share, and the pro forma net tangible
book value of the common stock as of such date would have been approximately
$ million, or $ per share. Assuming the offerings had occurred at
December 31, 1999, an immediate increase in net book value of $ per share to
the existing stockholders and an immediate pro forma dilution of $ per share
to new investors would have occurred. The following table shows the effect of
the offerings as if the offerings had occurred at December 31, 1999 and
illustrates the immediate increase in pro forma net tangible book value of
$ per share to the existing stockholders and an immediate pro forma dilution
of $ per share to new investors:

<TABLE>
<S> <C> <C>
Assumed initial public offering price per share.............. $
Pro forma net tangible book value per share as of
December 31, 1999....................................... $
Increase in net tangible book value per share
attributable to the offerings...........................
--------
Pro forma net tangible book value per share as of
December 31, 1999 after giving effect to the offerings.....
--------
Pro forma dilution per share to new investors................ $
========
</TABLE>

The foregoing table assumes the underwriters do not exercise their
overallotment option, and it does not reflect outstanding employee stock options
to purchase approximately shares of common stock. The terms of the options
provide for vesting over a period of time, generally to
years. Assuming all options are exercised, pro forma net tangible book value per
share would increase $ per share to $ per share.

The following table shows, on a pro forma as adjusted basis at December 31,
1999, the number of shares of common stock purchased from us, the total
consideration paid to us and the average price paid per share by the existing
stockholders and by new investors purchasing common stock from us in the
offerings:

<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION
------------------------ ------------------------ AVERAGE PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
------------- -------- ------------- -------- -------------
(IN MILLIONS) (IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Existing stockholders...... % $ % $
New investors..............
-------- -------- -------- -------- --------
Total................. % $ % $
======== ======== ======== ======== ========
</TABLE>

20
<PAGE> 23

CAPITALIZATION

The following table sets forth the total capitalization of our company as
of December 31, 1999:

- on a historical basis; and

- on a pro forma basis giving effect to the Combination and the sale of
shares of our common stock in the offerings and the application of
the estimated net proceeds from the offerings.

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 consolidated financial statements.

<TABLE>
<CAPTION>
AS OF
DECEMBER 31, 1999
----------------------
HISTORICAL PRO FORMA
---------- ---------
(IN THOUSANDS)
<S> <C> <C>
Indebtedness................................................ $ $
======== ========
Stockholders' equity:
Common stock, $1.00 par value per share, 1,000 shares
authorized, 1,000 shares issued and outstanding
historical, shares issued and outstanding pro
forma historical....................................... 1
Paid-in capital........................................... 213,091
Retained earnings......................................... 173,091
Other comprehensive income................................ 288
-------- --------
Total stockholders' equity............................. $386,471 $
-------- --------
Total capitalization................................... $386,471 $
======== ========
</TABLE>

21
<PAGE> 24

SELECTED HISTORICAL AND PRO FORMA
COMBINED FINANCIAL AND OTHER DATA

The following table sets forth selected historical financial and other data
for the Predecessor Company. 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 is derived from unaudited
financial statements. In addition, the following table sets forth selected pro
forma financial and other data, which reflect the historical results of
operations of the Predecessor Company, adjusted for (1) the acquisition of the
midstream natural gas business of Phillips in the Combination; (2) the
acquisition of Union Pacific Fuels; (3) 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;" (4) the offerings and the expected
application of the estimated proceeds; (5) the transfer to our company of
additional midstream natural gas assets acquired by Duke Energy or Phillips
prior to consummation of the Combination; and (6) the transfer to our company of
the general partner of TEPPCO; as if all had occurred as of January 1, 1999 for
income statement purposes and December 31, 1999 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.
The pro forma data set forth below are not necessarily indicative of results
that may occur in the future.

<TABLE>
<CAPTION>
PREDECESSOR COMPANY HISTORICAL
------------------------------------------------------------ PRO FORMA
1995 1996 1997 1998 1999(1)(2) 1999(1)
-------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<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 75,573 130,788 272,617
General and administrative......... 20,576 43,871 36,023 44,946 73,685 95,710
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 5,317,707
Operating income..................... 89,369 130,024 125,947 45,875 104,771 256,873
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 57,720 127,273 284,211
Interest expense..................... 20,115 12,747 51,113 52,403 52,915 159,092
-------- ---------- ---------- ---------- ---------- ----------
Earnings before income tax........... 70,914 120,274 84,618 5,317 74,358 125,119
Income tax........................... 37,299 35,665 33,380 3,289 31,029 56,946
-------- ---------- ---------- ---------- ---------- ----------
Net income........................... $ 33,615 $ 84,609 $ 51,238 $ 2,028 $ 43,329 $ 68,173
======== ========== ========== ========== ========== ==========
Earnings per share(3)................ $
==========
OTHER DATA:
Cash flow data:
Cash flow from operations.......... 173,357 (203,625) 173,136
Cash flow from investing
activities....................... (138,021) (243,625) (1,571,446)
Cash flow from financing
activities....................... (35,061) 162,514 1,398,934
Acquisitions and other capital
expenditures....................... $183,531 $ 524,730 $ 121,978 $ 185,479 $1,570,083 $ 429,847
EBITDA(4)............................ $128,310 $ 188,521 $ 203,432 $ 133,293 $ 258,061 $ 556,828
Gas transported and/or processed
(TBtu/d)........................... 1.9 2.9 3.4 3.6 5.1 7.3
NGLs production(MBbl/d).............. 55 79 108 110 192 400
</TABLE>

22
<PAGE> 25

<TABLE>
<CAPTION>
------------------------------------
1997 1998 1999(1)(2)
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
HISTORICAL SEGMENT INFORMATION:
Operating revenues:
Natural gas............................................... $1,683,483 $1,497,901 $2,483,197
NGLs...................................................... 423,680 309,380 1,365,577
Intersegment.............................................. (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
========== ========== ==========
Operating income:
Natural gas............................................... $ 164,464 $ 90,520 $ 158,356
NGLs...................................................... (386) 2,404 22,390
Corporate................................................. (38,131) (47,049) (75,975)
---------- ---------- ----------
Total operating income............................. $ 125,947 $ 45,875 $ 104,771
========== ========== ==========
EBITDA(4):
Natural gas............................................... $ 239,841 $ 176,436 $ 305,919
NGLs...................................................... (386) 2,404 33,048
Corporate................................................. (36,023) (45,547) (80,906)
---------- ---------- ----------
Total EBITDA....................................... $ 203,432 $ 133,293 $ 258,061
========== ========== ==========
Total assets:
Natural gas............................................... $1,609,835 $2,859,667
NGLs...................................................... 5,137 225,702
Corporate................................................. 155,866 386,466
---------- ----------
Total assets....................................... $1,770,838 $3,471,835
========== ==========
</TABLE>

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

(1) Includes $34 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) Earnings per share is not presented for historical periods since the
Predecessor Company was an indirect wholly owned subsidiary of Duke Energy.
Pro forma earnings per share reflects outstanding shares after the
Combination and the anticipated issuance of common stock from the offerings.

(4) 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 included as a
supplemental disclosure because it may provide useful information regarding
our ability to service debt and to fund capital expenditures.

(5) 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.

(6) Based on the NYMEX Henry Hub prices for the years indicated.

(7) We expect to have $ billion of short-term indebtedness outstanding after
the offerings and expect to convert a significant portion of this short-term
debt to long-term debt as market conditions permit. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

23
<PAGE> 26

FIVE-YEAR PRO FORMA COMBINED FINANCIAL AND OTHER DATA

<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <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
Costs of natural gas and petroleum products..... 1,729,278 2,976,059 3,798,465 3,527,533 4,554,776
Operating, maintenance, general and
administrative costs.......................... 395,662 389,746 423,327 460,990 488,844
---------- ---------- ---------- ---------- ----------
Net margin(1)................................... $ 288,931 $ 632,468 $ 547,280 $ 314,174 $ 530,960
========== ========== ========== ========== ==========
OTHER DATA:
Gas transported and/or processed (TBtu/d)....... 5.4 6.5 7.5 7.3 7.3
NGLs production(MBbl/d)......................... 277 313 358 373 400
MARKET DATA:
Average NGLs (price per gallon)(2).............. $.28 $.38 $.34 $.25 $.33
Average natural gas (price per MMBtu)(3)........ $1.64 $2.59 $2.59 $2.11 $2.27
</TABLE>

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

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

(3) Based on the NYMEX Henry Hub prices for the years indicated.

24
<PAGE> 27

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. This discussion should be read in conjunction with "Selected
Historical and Pro Forma Combined Financial and Operating Data," "Five-Year Pro
Forma Combined 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.

Unless the context otherwise requires, the discussion of our business
contained in this section relates to the Predecessor Company on an historical
basis without giving 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.

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 , 2000, after giving
effect to the Combination, approximately % 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.

25
<PAGE> 28
The following table 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
table 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 table below were primarily affected
by (1) fluctuations in raw natural gas volumes processed, including increases
resulting from our acquisitions and additions and (2) the Predecessor Company's
historical risk management activities.

[GRAPH]

Note: The weighted average NGL prices set forth in the table 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 quarter 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 $ 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 in 1999 have spurred increased natural gas drilling
activity. For example, the number of actively drilling rigs in North America has
increased by approximately 65% from approximately 760 in February 1999 to more
than 1,270 in February 2000. This drilling activity increase is expected to have
a positive effect on natural gas volumes gathered and processed in the near
term.

26
<PAGE> 29

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. Generally,
we sell the NGLs and use a portion of the proceeds to cover any shrinkage
in the Btu content of the natural gas as a result of our processing.
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 Btus in the average
price of natural gas throughout such period would have resulted in changes in
pre-tax net income of approximately $24.0 million and ($1.0) million,
respectively. See "-- Quantitative and Qualitative Disclosure About Market
Risks."

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.

27
<PAGE> 30

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. Our 1999 results
of operations include $34.0 million of hedging losses. After the Combination, we
will direct 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 Risk."

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 , 2000, we combined the gas gathering, processing, marketing and
NGLs businesses of Duke Energy and Phillips. In connection with the Combination,
Phillips transferred all of its interest in its subsidiaries that conducted its
midstream natural gas business to Field Services LLC, our subsidiary formed in
December of 1999 to hold all of Duke Energy's gas gathering and processing
business. In connection with the Combination, Duke Energy and Phillips also
transferred to Field Services LLC additional midstream natural gas assets
acquired by Duke Energy or Phillips prior to consummation of the Combination,
including the Mid-Continent gathering and processing assets of Conoco and
Mitchell Energy. In addition, concurrent 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 Field
Services LLC, with Duke Energy indirectly, through us, holding the remaining
69.7% of the outstanding member interests. In connection with the closing of the
Combination, Field Services LLC borrowed approximately $ billion 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 is accounted
for as a purchase of the Phillips midstream natural gas business.

Concurrently with the consummation of the offerings of common stock, the
subsidiary of Phillips that indirectly holds Phillips' interest in Field
Services LLC will be merged into our company, and we will issue shares of our
common stock to Phillips. After the merger and completion of the offerings of
common stock, Duke Energy and Phillips together will own % of our outstanding
common stock. The exact allocation between Duke Energy and Phillips of shares of
our common stock will be determined by the average of the closing prices of our
common stock on its first five trading days on the New York Stock Exchange
Composite Tape. Assuming that the five-day average price is the same as the
assumed initial public offering price, following the offerings, Duke Energy will
own approximately % and Phillips will own approximately % of our outstanding
common stock. Although the exact allocation may vary, Duke Energy will, in all
events, continue to control our company through its share ownership and
representation on our Board of Directors.

PRO FORMA COMBINED RESULTS OF OPERATIONS

The following is a discussion of the pro forma operating revenues, cost of
sales, operating, general and administrative costs and net margin 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.

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. The pro forma data on which this
discussion is based should not be considered indicative of (1) 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 (2) the results of
our future operations.

28
<PAGE> 31

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. This increase primarily 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."

Costs and Expenses. 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. Operating, maintenance, and general and
administrative expenses increased $27.8 million, or 6%, from $461.0 million to
$488.8 million. This increase was primarily due to a $7.0 million increase in
allocated corporate overhead from Duke Energy associated with increased activity
levels and other inflationary factors.

Net Margin. Net margin increased $216.8 million, or 69%, from $314.2
million to $531.0 million. This increase was largely the result of higher
average NGL prices minimally offset by higher natural gas prices. The increase
in net margin was partially offset by a $34.0 million loss from our hedging
activity.

1998 COMPARED WITH 1997

Operating Revenues. Operating revenues decreased $466.4 million, or 10%,
from $4,769.1 million to $4,302.7 million. This decrease was primarily due to
commodity prices, 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 our fourth quarter 1997
acquisition of Highlands Gas Partners and 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 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.

Costs and Expenses. 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. Operating and general and
administrative expenses increased $37.7 million, or 9%, from $423.3 million to
$461.0 million. This increase primarily was due to the Highlands Gas Partners
acquisition, a processing facility restart and higher property tax accrual
relating to property additions.

Net Margin. Net margin decreased $233.1 million, or 43% from $547.3 million
to $314.2 million. This decrease largely was the result of substantially lower
commodity prices.

QUARTERLY PRO FORMA COMBINED RESULTS

The following table sets forth unaudited pro forma combined financial and
operating data for our company on a quarterly basis for each of 1998 and 1999.

29
<PAGE> 32

<TABLE>
<CAPTION>
PRO FORMA
-----------------------------------------------------------------------------
1998 1999
------------------------------------- -------------------------------------
FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER UNIT DATA)
<S> <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
Costs of natural gas and
petroleum products............ 902 951 900 775 762 923 1,313 1,557
Operating, maintenance, general
and administrative costs...... 109 113 115 124 125 116 120 128
Net margin(1)................... 102 79 80 53 72 119 164 176
Weighted average NGL price (per
gallon)(2).................... .28 .26 .20 .22 .22 .30 .39 .41
</TABLE>

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

(2) Based on index prices from the Mont Belvieu and Conway market hubs that are
weighed by our component and location mix for the years indicated. NGL
prices have significantly affected our historical results. However, there
are many other factors that have affected, and in the future likely will
affect, our results, including fluctuations in raw natural gas volumes
gathered, processed, transported, marketed and stored, and our risk
management activities.

HISTORICAL RESULTS OF OPERATIONS

The following is a discussion of the historical results of operations of
the Predecessor Company.

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

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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.

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.

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 $0.09 per gallon lower and natural gas prices were unchanged,
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.

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.

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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.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY PRIOR TO THE COMBINATION

The Predecessor Company's capital investments and acquisitions have been
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, $ million of advances from Duke
Energy were capitalized to equity and $ million of advances from Phillips
were capitalized.

In March 2000, Field Services LLC 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 March ,
2000 Field Services LLC borrowed approximately $ 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. At March , 2000 our outstanding commercial paper had
maturities ranging from days to days and had annual interest rates between
% and %. 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 , 2001 and bears 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 .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. Upon completion of the offerings, Duke Energy Field Services Corporation
will assume Field Services LLC's obligations under the facility.

Proceeds of the offerings will be used to repay a portion of our
outstanding commercial paper, and the credit facility will be permanently
reduced by the amount of such proceeds. The amount available under the credit
facility and corresponding commercial paper program will be further reduced by
the amount, if any, of long-term debt we may issue, but in no event will the
credit facility be reduced to below $1.0 billion. Upon completion of the
offerings and application of the net proceeds, we expect to have outstanding
$ billion of indebtedness. The debt levels reflected in the pro forma
combined financial statements are based upon the indebtedness we anticipate
having outstanding upon consummation of the financing transactions described
above and the offerings. In the future, our debt levels will vary depending on
our liquidity needs, capital expenditures and cash flow.

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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 facility, 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.

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. 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 facility or other available sources of financing.

CASH FLOWS

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 $1,404.4 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 $(15.0) million and $5.0 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 $24.0 million and ($1.0) 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.

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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.

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 , 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. During 1999, our risk management
was directed by Duke Energy's centralized program for controlling, managing and
coordinating its management of risks. After the Combination, we will direct our
risk management activities independently of Duke Energy.

We intend to 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 will look 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.

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INTEREST RATE RISK

Prior to the Combination, our subsidiaries had no material interest rate
risk associated with debt used to finance our operations due to limited third
party borrowings. After completion of the offerings, we expect to have
approximately $ billion outstanding under a commercial paper program. As a
result, we are exposed to market risks 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. Following the application of the net proceeds
of the offerings, and 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 $
million.

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 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.

YEAR 2000

We did not experience any disruption to our operations resulting from the
transition to the year 2000. We completed our year 2000 readiness program in
November 1999. Our systems will continue to be monitored throughout the year.
The total cost of the program, including costs such as consulting and contract
costs, was approximately $2.2 million. These costs exclude replacement systems
that, in addition to being year 2000 ready, provided significantly enhanced
capabilities that benefit operations in future periods.

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BUSINESS

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

- 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.

During 1999, our natural gas gathering, processing, transportation,
marketing and storage segment produced $981.5 million of gross margin and $583.1
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.

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 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.

On March 31, 2000, we obtained by transfer from Duke Energy the general
partner of TEPPCO. 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
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strategy. 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 (1) 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
(2) pursuant to the incentive cash distribution provisions, receives 50% of any
increase in TEPPCO's per unit cash distributions.

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 1.8 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. 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 Offshore
Gulf of Mexico, Onshore Gulf of Mexico, Western Canada and Rocky Mountains, that
could have significant growth in production which provides 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;

- 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

- 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 also 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

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NGL market presence by investing in additional NGL infrastructure,
including pipelines, fractionators and terminals.

- Increase our presence in high growth production areas. 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.

NATURAL GAS GATHERING, PROCESSING, TRANSPORTATION, MARKETING AND STORAGE

OVERVIEW

Our raw natural gas gathering and processing operations consist 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.

We currently gather, process and/or transport 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 $583.1 million of EBITDA.

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.

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:

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- 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 gas and NGLs value derived from our
gathering and processing activities, with the producer retaining the
remainder of the value. These types 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 the
gathering, processing and/or treating of raw natural gas. Our revenue
stream under 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. Generally,
we sell the NGLs and use a portion of the proceeds to cover any shrinkage
in the Btu content of the natural gas as a result of our processing.
Accordingly, under these contracts, we are exposed to increases in the
price of natural gas and decreases in the price of NGLs, as well as the
spread between the two. In December 1999, after giving effect to the
Combination, approximately 15% of our gross margin was generated from
keep-whole 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.

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
industry studies indicate contain significant quantities of undeveloped natural
gas reserves and are expected to experience

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significant increases in drilling activity. 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.

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. Low pressure systems allow wells, which produce at
progressively lower pressures as they age, to remain connected to gathering
systems and continue to produce for longer periods of time. 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 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.

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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 "greenfield" opportunities. The majority of the financing plans we
offer are asset-based and we require that our producers satisfy risk/reward
tolerances. 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 currently owned or operated by us.
<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 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.

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<PAGE> 44

- 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 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 experiencing increased production through the application of
new technologies like 3-D seismic and horizontal drilling as well as from
in-fill drilling, well recompletions or downspacing 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 interests in 21 natural gas processing plants in
this region, which are strategically located to access the production of the
Permian Basin, and 12,890 miles of gathering pipelines. 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. We own interests in 21 natural gas processing
plants and 30,820 miles of gathering pipelines in this region. 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
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<PAGE> 45

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 interests in 11 natural gas
processing plants and 5,869 miles of gathering pipelines in this region. 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 interests in
eight gas processing plants, 3,008 miles of gathering and intrastate
transmission pipelines and the Spindletop gas storage facility. 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.

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<PAGE> 46

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 interests in 11 natural gas processing plants, 3,765
miles of gathering pipelines and a 330 mile intrastate transmission pipeline in
this region. 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 interests in
eight gas processing plants and 700 miles of oil and raw natural gas gathering
and transmission pipelines. 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 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 and operate three gas processing and treating 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,
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<PAGE> 47

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.

We believe that significant growth opportunities exist in this region, as
less than 20% of the gathering and processing assets in the area are owned by
midstream gathering and processing companies. 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. 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
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.

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

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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 and our largest
sales customers are Phillips, ExxonMobil and Dow Chemical. Our three principal
competitors are Dynegy, Koch and Enterprise.

TEPPCO

On March 31, 2000, we obtained by transfer from Duke Energy, the general
partner of TEPPCO, a publicly traded master 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

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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.

The general partner of TEPPCO manages and directs TEPPCO pursuant to 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
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 (1)
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 (2) pursuant to 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
$ 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,
please see "Natural Gas Gathering, Processing, Transportation, Marketing and
Storage--Raw Natural Gas Supply Arrangements."

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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
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 pursuant to 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
48
<PAGE> 51

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.

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

49
<PAGE> 52

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.

The FERC has instituted a rulemaking relating to the treatment of gathering
facilities on the outer continental shelf in the Gulf of Mexico. The proposed
rules would create additional regulatory reporting requirements for offshore
gatherers like us. This rulemaking, if adopted as proposed, could also place us
at a competitive disadvantage relative to other offshore gatherers that are
owned by producers of natural gas because we do not currently have systems and
procedures in place to meet such requirements.

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.

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<PAGE> 53

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.

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 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 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

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<PAGE> 54

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 MACT standard will affect us
and our competitors in a like manner. 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
produced waters and other 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 as
hazardous waste. Natural gas and NGLs transported in pipelines may also 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. 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 to
transfer liability 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 management responsibility for environmental
remediation, and the insurance partner
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<PAGE> 55

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. This innovative approach promotes pro-active site cleanup
and closure, reduces internal resource needs for managing remediation, and may
improve the marketability of assets based on transferability of this insurance
coverage. In August 1996, we acquired certain gas gathering and processing
assets in three states from Mobil Corporation. Pursuant to 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

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 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. 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 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.

LEGAL PROCEEDINGS

In November 1997, Chevron U.S.A. sued GPM Gas Corporation, one of our
subsidiaries, in the United States District Court for the Western District of
Texas, Midland Division, for alleged breach by GPM Gas Corporation of favored
nations clauses in several 1961 gas supply contracts. The case was tried in
October 1998, and in September 1999, the trial court issued an opinion and final
judgment against GPM for $13.8 million through July 1998, plus attorneys' fees
and interest for the period after July 1998. GPM Gas Corporation has appealed
the judgment to the U.S. Court of Appeals for the Fifth Circuit.

In recent years, the midstream natural gas industry has seen an increase in
the number of class actions in suits involving royalty disputes, mismeasurement
and mispayment. Although the industry has seen these types
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of cases before, they were previously typically brought by a single plaintiff or
small group of plaintiffs. Many of these cases are now being brought as class
actions or under the Civil False Claims Act. We are currently named defendants
in a number of these types of cases. Although we believe we have meritorious
defenses to these cases and will continue to vigorously defend against them,
these class actions are expected to be costly and time consuming to defend.

In addition to the foregoing, from time to time, we are named as parties in
legal proceedings arising in the ordinary course of our business. We believe we
have meritorious defenses to all of these lawsuits and legal proceedings and
will vigorously defend against them. Based on our evaluation of pending matters
and after consideration of reserves established, we believe that the resolution
of these proceedings will not have a material adverse effect on our business,
financial position or results of operations.

EMPLOYEES

As of February 29, 2000, we had approximately 2,700 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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<PAGE> 57

MANAGEMENT

EXECUTIVE OFFICERS AND DIRECTORS

The following table provides information regarding our executive officers
and directors:

<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
Jim W. Mogg........................... 51 Director and Chairman of the Board,
President and Chief Executive
Officer
Michael J. Panatier................... 51 Nominee for Director and Vice Chairman
of the Board
Mark A. Borer......................... 45 Senior Vice President, Southern Region
Michael J. Bradley.................... 45 Senior Vice President, Northern Region
David D. Frederick.................... 40 Senior Vice President and Chief
Financial Officer
Robert F. Martinovich................. 42 Senior Vice President, Western Region
William J. Slaughter.................. 52 Executive Vice President
Martha B. Wyrsch...................... 42 Senior Vice President, General Counsel
and Secretary
Fred J. Fowler........................ 54 Director
J.J. Mulva............................ 53 Nominee for Director
Richard B. Priory..................... 53 Director
</TABLE>

Jim W. Mogg is Chairman of the Board, President and Chief Executive Officer
of our company. Mr. Mogg also serves as Senior Vice President--Field Services
for Duke Energy. Mr. Mogg was President and Chief Executive Officer of the
Predecessor Company from 1994 until the Combination. Mr. Mogg is also a director
of TEPPCO. Mr. Mogg has been in the energy industry since 1973.

Michael J. Panatier is a nominee for Director and Vice Chairman of Duke
Energy Field Services Corporation. Mr. Panatier served as Senior Vice President
of Gas Processing and Marketing for Phillips from 1998 until the Combination.
From 1994 until the Combination, he also served as President and Chief Executive
Officer of GPM Gas Corporation, a subsidiary of Phillips. Mr. Panatier has been
in the energy industry since 1975.

David D. Frederick is Senior Vice President and Chief Financial Officer of
our company. Mr. Frederick held the same position with the Predecessor Company
from 1998 until the Combination. From 1996 until 1998, Mr. Frederick served as
Vice President and Controller of Panhandle Eastern Pipe Line Company and
Trunkline Gas Company. From 1993 until 1996, Mr. Frederick served as Controller
of Panhandle Eastern Pipe Line Company. Mr. Frederick has been in the energy
industry since 1988.

Mark A. Borer is Senior Vice President, Southern Region of our company. Mr.
Borer held the same position with the Predecessor Company from 1999 until the
Combination. From 1992 until 1999, Mr. Borer served as Vice President of Natural
Gas Marketing for Union Pacific Fuels, Inc. Mr. Borer has been in the energy
industry since 1978.

Michael J. Bradley is Senior Vice President, Northern Region of our
company. Mr. Bradley held the same position with the Predecessor Company from
1994 until the Combination. Mr. Bradley has been in the energy industry since
1979.

Robert F. Martinovich is Senior Vice President, Western Region of our
company. Mr. Martinovich was Senior Vice President of GPM Gas Corporation, a
subsidiary of Phillips, from 1999 until the Combination. From 1996 until 1999,
Mr. Martinovich was Vice President for the Oklahoma Region for GPM Gas
Corporation, and from 1994 until 1996, he was Business Development Manager for
GPM Gas Services Company. Mr. Martinovich has been in the energy industry since
1980.

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<PAGE> 58

William J. Slaughter is Executive Vice President of our company. Mr.
Slaughter held the position of Advisor to the Chief Executive Officer of the
Predecessor Company from 1998 until his appointment as Executive Vice President
in 2000. From 1997 until 1998, Mr. Slaughter was Vice President of Energy
Services for Duke Energy. From 1994 until 1997, Mr. Slaughter served as Vice
President of Corporate Strategic Planning for Pan Energy and President of Pan
Energy International Development Corporation. Mr. Slaughter has been in the
energy industry since 1981.

Martha B. Wyrsch is Senior Vice President, General Counsel and Secretary of
our company. Ms. Wyrsch held the same position with the Predecessor Company from
1999 until the Combination. Ms. Wyrsch also currently serves as Vice President
and General Counsel -- Energy Transmission for Duke Energy. From 1997 until
1999, Ms. Wyrsch served as Vice President, General Counsel and Secretary of K N
Energy, Inc. From 1996 until 1997, Ms. Wyrsch served as Vice President, Deputy
General Counsel and Secretary of K N Energy, Inc. Ms. Wyrsch served K N Energy,
Inc. in a variety of positions from 1991 to 1996, including Assistant General
Counsel, Senior Counsel and Assistant Secretary. Ms. Wyrsch has been in the
energy industry since 1991.

Fred J. Fowler, a Director of our company, is Group President -- Energy
Transmission of Duke Energy and has held that position since 1997. Mr. Fowler
served as Group Vice President of Pan Energy from 1996 until 1997. From 1994
until 1996, Mr. Fowler served as President of Texas Eastern Transmission
Company. Mr. Fowler is also a director of TEPPCO. Mr. Fowler has been in the
energy industry since 1968.

J.J. Mulva, a nominee for Director of our company, is Chairman of the
Board, President and Chief Executive Officer of Phillips Petroleum Company and
has held these positions since 1999. From 1994 to 1999, Mr. Mulva served as
President and Chief Operating Officer of Phillips. Mr. Mulva has been in the
energy industry since 1973.

Richard B. Priory, a Director of our company, is the Chairman, President
and Chief Executive Officer of Duke Energy and has held that position since
1998. Mr. Priory served as Chairman and CEO of Duke Energy from 1997 to 1998.
From 1994 until 1997, Mr. Priory served as President and Chief Operating Officer
of Duke Energy. Mr. Priory has been in the energy industry since 1974.

We currently have three directors and two nominees for director. After this
offering is completed, we will have a total of 11 directors. Duke Energy and
Phillips have entered into an agreement that provides that they will vote their
shares of common stock after this offering to elect a Board of Directors of 11
members comprised of seven individuals designated by Duke Energy, at least two
of whom must be independent, and four individuals designated by Phillips, at
least one of whom must be independent. Under the terms of the agreement, the
number of designees of each of Duke Energy and Phillips is subject to
reallocation depending on the relative interests in our company held by Duke
Energy and Phillips. For a more detailed discussion of certain voting and other
corporate governance provisions that will be in effect after this offering, see
"Description of Capital Stock -- Stockholders Agreement" and "-- Supermajority
Requirements." Each director is elected annually by our stockholders for a
one-year term.

COMMITTEES OF THE BOARD OF DIRECTORS

Upon completion of this offering, our Board of Directors will establish an
Audit Committee and a Compensation Committee. The functions of the Audit
Committee will be to:

- recommend annually to our Board of Directors the appointment of our
independent auditors;

- discuss and review in advance the scope and the fees of our annual audit
and review the results of the annual audit with our independent auditors;

- review and approve non-audit services of our independent auditors;

- review the adequacy of major accounting and financial reporting policies;

- review compliance with our major accounting and financial reporting
policies;

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<PAGE> 59

- review our management's procedures and policies relating to the adequacy
of our internal accounting controls and compliance with applicable laws
relating to accounting practices; and

- review our risk management policies and activities.

The Audit Committee will initially consist solely of independent directors.

The functions of the Compensation Committee will be to review and approve
annual salaries, bonuses, and grants of stock options under our 2000 Long-Term
Incentive Plan for all executive officers and key members of our management
staff, and to review and approve the terms and conditions of all employee
benefit plans or changes to these plans. Following the offerings, we will have a
Compensation Committee consisting solely of independent directors.

BOARD COMPENSATION

Directors who are also our employees do not receive a retainer or fees for
service on our Board of Directors or any committees. We pay non-employee members
of our Board of Directors for their service as directors. Directors who are not
employees receive an annual fee of $ , an annual stock option grant
equal to $ and a fee of $ for attendance at each meeting of our
Board of Directors. All of our directors are reimbursed for reasonable
out-of-pocket expenses incurred in attending meetings of our Board of Directors
or committees and for other reasonable expenses related to the performance of
their duties as directors.

EXECUTIVE COMPENSATION

The following table sets forth compensation information for the year ended
December 31, 1999 for the Chief Executive Officer and each of our next five most
highly compensated executive officers. These six individuals are referred to in
this prospectus as the "Named Executive Officers."

<TABLE>
<CAPTION>
ANNUAL COMPENSATION LONG-TERM COMPENSATION
-------------------------------- ------------------------------------
OTHER RESTRICTED SECURITIES
ANNUAL STOCK UNDERLYING LTIP ALL OTHER
SALARY BONUS COMPENSATION AWARDS STOCK OPTIONS PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION ($) ($) ($)(4) ($) (#) ($) ($)(12)
- --------------------------- ------- ------- ------------ ---------- ------------- ------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Jim W. Mogg(1)............ 256,883 104,019 -- 947,250(5) 41,300(10) 51,964 106,761
Chairman, President and
Chief Executive Officer
Michael J. Panatier(2).... 333,000 351,445 -- 82,971(6) 24,200(11) -- 15,266
Director and Vice
Chairman of the Board
David D. Frederick(1)..... 163,542 56,683 -- 257,025(7) 15,100(10) 19,262 173,997
Senior Vice President and
Chief Financial Officer
Mark A. Borer(1)(3)....... 139,604 49,187 -- 167,063(8) 16,800(10) -- 241,959
Senior Vice President,
Southern Region
Michael J. Bradley(1)..... 192,317 68,200 -- 296,138(9) 17,300(10) 19,503 257,300
Senior Vice President,
Northern Region
Robert F. Martinovich(2)... 169,740 107,749 -- -- 8,400(11) -- 12,305
Senior Vice President,
Western Region
</TABLE>

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

(1) Prior to the offerings all compensation paid to Messrs. Mogg, Frederick,
Borer and Bradley was paid by Duke Energy and was attributable to services
provided to the Predecessor Company.

(2) Prior to the offerings all compensation paid to Messrs. Panatier and
Martinovich was paid by Phillips.

(3) Mr. Borer joined the Predecessor Company in April 1999. Amounts shown
relate to the period from April 1999 to December 31, 1999.

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<PAGE> 60

(4) Perquisites and other personal benefits received by each Named Executive
Officer did not exceed the lesser of $50,000 or 10% of any such officer's
salary and bonus disclosed in the table.

(5) At December 31, 1999, Mr. Mogg held an aggregate of 18,000 restricted
shares of Duke Energy common stock having a value of $902,250. Dividends
are paid on such shares. The vesting of these shares is determined by,
among other things, the performance of the Predecessor Company.

(6) At December 31, 1999, Mr. Panatier held an aggregate of 14,564 restricted
shares of Phillips common stock having a value of $684,508.

(7) At December 31, 1999, Mr. Frederick held an aggregate of 4,600 restricted
shares of Duke Energy common stock having a value of $230,575. Dividends
are paid on such shares. The vesting of these shares is determined by,
among other things, the performance of the Predecessor Company.

(8) At December 31, 1999, Mr. Borer held an aggregate of 3,000 restricted
shares of Duke Energy common stock having a value of $150,375. Dividends
are paid on such shares. One third of the restricted stock award will vest
each year on April 1, beginning on April 1, 2000.

(9) At December 31, 1999, Mr. Bradley held an aggregate of 5,300 restricted
shares of Duke Energy common stock having a value of $265,663. Dividends
are paid on such shares. The vesting of these shares is determined by,
among other things, the performance of the Predecessor Company.

(10) Represents options granted by Duke Energy to purchase shares of Duke Energy
common stock.

(11) Represents options granted by Phillips to purchase shares of Phillips
common stock.

(12) All Other Compensation column includes the following:

- Matching contributions under the Duke Energy Retirement Savings Plan as
follows: J. Mogg, $9,600; D. Frederick, $9,434; M. Borer, $5,550; M.
Bradley, $9,600.

- Make-whole matching contribution credits under the Duke Energy Executive
Savings Plan as follows: J. Mogg, $10,111; D. Frederick, $2,020; M.
Borer, $2,775; M. Bradley, $3,977.

- Matching contributions under the Phillips Thrift Plan as follows: M.
Panatier, $2,000; R. Martinovich, $2,000.

- Matching contributions under the Phillips Long-Term Stock Savings Plan as
follows: M. Panatier, $12,580; R. Martinovich, $10,143.

- Early payment of banked vacation time benefit earned under Duke Energy
benefits program as follows: J. Mogg, $67,624; M. Bradley, $28,757.

- Supplemental relocation payments made under Duke Energy's relocation
policy as follows: M. Borer, $33,634.

- Retention bonuses paid by Duke Energy as follows: D. Frederick, $162,500;
M. Borer, $200,000; M. Bradley, $209,000.

- Mortgage rate differential payments paid by Duke Energy to account for
increased mortgage payments due to employee relocation as follows: M.
Bradley, $2,353.

- Payment of taxes owed by employee as follows: J. Mogg, $19,426; D.
Frederick, $43; M. Bradley, $3,613.

- Life insurance premiums paid by Phillips as follows: M. Panatier, $686;
R. Martinovich, $162.

EMPLOYMENT AGREEMENTS

We have entered into an employment agreement with Mr. Panatier which
provides for a term of two years from the closing of the Combination. During the
term of this employment agreement, Mr. Panatier will receive a monthly salary of
$ , which may be increased upon the recommendation of our compensation
committee. The agreement also provides for a target bonus of % of Mr.
Panatier's annual base salary. Mr. Panatier is entitled to participate in all
our benefit plans on the same basis as other similarly-situated executives of
our company.

Mr. Panatier will also receive annual long-term incentive awards in the
form of stock option grants with a value equal to % of his annual base salary
and restricted stock awards with a value equal to % of his

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annual base salary. While the specific terms of these awards will generally be
determined by our compensation committee, any awards made during the initial
term of this agreement will vest on the second anniversary of the completion of
the offerings. The employment agreement also provides for a restricted stock
retention award, to be valued at % of his annual base salary, to be granted on
the completion of the offerings. This restricted stock award vests 50% on the
first anniversary of the effective date of the employment agreement and 50% on
the second anniversary if Mr. Panatier is employed on the vesting date.

If we terminate Mr. Panatier's employment for any reason other than death,
disability or cause or if Mr. Panatier's terminates his employment for cause,
all long-term incentive awards and his restricted stock awards will immediately
vest. In addition, if a change of control of our company occurs during the
second year of the employment agreement and prior to such termination, Mr.
Panatier will also be entitled to a lump sum severance payment equal to % of
his annual salary in effect at the time, plus his target bonus and to
participate in our group medical plan (unless Mr. Panatier is eligible for
coverage by a subsequent employer) for a period of two years following such
termination.

2000 LONG-TERM INCENTIVE PLAN

General. We have adopted a Long-Term Incentive Plan. The plan allows us to
grant incentive awards to our employees and those of our subsidiaries and to
non-employee members of our Board of Directors. The plan provides for the grant
of:

- stock options (including both incentive stock options and nonqualified
stock options);

- stock appreciation rights;

- restricted stock;

- performance awards;

- phantom stock; and

- dividend equivalents.

The purpose of the plan is to strengthen our ability to attract, motivate
and retain employees and directors and to provide an additional incentive for
employees.

Reservation of Shares. We have reserved shares of common
stock for issuance under plan, provided that no more than shares of
common stock may be issued pursuant to all awards of restricted stock,
performance awards or phantom stock under the plan. The shares of common stock
to be issued under the plan shall be made available from authorized but unissued
shares of common stock. If any shares of common stock that are the subject of an
award are not issued and cease to be issuable for any reason, such shares will
no longer be charged against such maximum share limitation and may again be made
subject to awards under the plan. In the event of certain corporate
reorganizations, recapitalizations, or other specified corporate transactions
affecting us or our common stock, proportionate adjustments may be made to the
number of shares available for grant under the plan, the applicable maximum
share limitations under the plan, and the number of shares and prices under
outstanding awards at the time of the event.

Administration. The plan will be administered by the Compensation
Committee, or such other committee or subcommittee of the Board of Directors
designates. Subject to certain limitations, the committee has the authority to
determine the persons to whom awards are granted, the types of awards to be
granted, the time at which awards will be granted, the number of shares, units
or other rights subject to each award, the exercise, base or purchase price of
an award (if any), the time or times at which the award will become vested,
exercisable or payable, and the duration of the award. The committee also has
the power to interpret the plan and make factual determinations and may provide
for the acceleration of the vesting or exercise period of an award at any time
prior to its termination or upon the occurrence of specified events.

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<PAGE> 62

Change in Control. The committee may provide in an individual award
agreement for the effect of a "change in control" (as defined in the plan) upon
an award granted under the plan. Such provisions may include:

- the acceleration or extension of time periods for purposes of exercising,
vesting in, or realizing gain from an award;

- the waiver or modification of performance or other conditions related to
payment or other rights under an award;

- providing for the cash settlement of an award; or

- such other modification or adjustment to an award as the committee deems
appropriate.

Term and Amendment. The plan has a term of ten years, subject to earlier
termination or amendment by our Board of Directors. The Board of Directors may
amend the plan at any time, except that shareholder approval is required for
amendments that would change the persons eligible to participate in the plan,
increase the number of shares of common stock reserved for issuance under the
plan, allow the grant of options at an exercise price below fair market value,
or allow the repricing of options without shareholder approval.

2000 Plan Benefits. Currently, all employees are expected to be considered
by the committee for participation in the plan. The number of persons eligible
to participate in the plan and the number of grantees may vary from year to
year.

OPTION GRANTS IN LAST FISCAL YEAR

In the fiscal year ended December 31, 1999, none of the named executive
officers received options to purchase our common stock, nor were they entitled
to exercise any such stock options. None of the named executive officers held
options to purchase our common stock at December 31, 1999.

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RELATIONSHIP WITH DUKE ENERGY AND PHILLIPS

On March , 2000, we combined the midstream natural gas businesses of Duke
Energy and Phillips. In connection with the Combination, Phillips transferred
all of its interest in its subsidiaries that conducted its midstream natural gas
business to Field Services LLC, our subsidiary that was formed in December 1999
to hold all of Duke Energy's gas gathering and processing business. In
connection with the Combination, Duke Energy and Phillips also transferred to
Field Services LLC the midstream natural gas assets acquired by Duke Energy or
Phillips prior to consummation of the Combination, including the Mid-Continent
gathering and processing assets of Conoco and Mitchell Energy. In addition,
concurrent 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 Field Services LLC, with Duke Energy
indirectly, through us, holding the remaining 69.7% of the outstanding member
interests. In connection with the closing of the Combination, Field Services LLC
borrowed approximately $ billion 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.

Concurrently with the consummation of the offerings of common stock, the
subsidiary of Phillips that indirectly holds Phillips' interests in Field
Services LLC will be merged into us, and we will issue shares of our common
stock to Phillips. After the merger and completion of the offerings of common
stock, Duke Energy and Phillips together will own % of our outstanding
common stock (assuming the underwriters do not exercise their over-allotment
option). The exact allocation between Duke Energy and Phillips of shares of our
common stock will be determined by the average of the closing prices of our
common stock on its first five trading days on the New York Stock Exchange
Composite Tape. Assuming that the five-day average price is the same as the
assumed initial public offering price, following the offerings, Duke Energy will
own approximately % and Phillips will own approximately % of our
outstanding common stock (assuming the underwriters do not exercise their
over-allotment option). Although the exact allocation may vary, Duke Energy
will, in all events, continue to control our company through its share ownership
and representation on our Board of Directors.

There are significant transactions and relationships between us, Duke
Energy and Phillips. For purposes of governing these ongoing relationships and
transactions, we will enter into, or continue in effect, the agreements
described below. We intend that the terms of any future transactions and
agreements between us and Duke Energy or Phillips will be at least as favorable
to us as could be obtained from third parties. We will advise our Board of
Directors in advance of any such proposed transactions or agreements with Duke
Energy or Phillips that are material to us. In evaluating these terms and
provisions, our Board of Directors will use appropriate procedures in light of
the Board's fiduciary duties. Depending on the nature and size of the particular
transaction, in any such reviews, our Board of Directors may rely on our
management's knowledge, use outside experts or consultants, secure appropriate
appraisals, refer to industry statistics or prices, or take other actions as are
appropriate under the circumstances.

TRANSACTIONS WITH DUKE ENERGY

SERVICES AGREEMENT

We have entered into a Services Agreement with Duke Energy and some of its
subsidiaries, effective March , 2000. Under this agreement, Duke Energy and
those subsidiaries will provide us with various staff and support services,
including information technology products and services, payroll, employee
benefits, corporate insurance, cash management, ad valorem taxes and shareholder
services. The above services are priced on the basis of a monthly charge.
Additionally, we may use other Duke Energy services subject to hourly rates,
including legal, internal audit, tax planning, human resources and security
departments. This agreement expires on December 31, 2000 unless renewed by the
mutual agreement of the parties. We believe that overall charges under this
agreement will not exceed charges we would have incurred had we obtained similar
services from outside sources.

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LICENSE AGREEMENT

Duke Energy has licensed to us a non-exclusive right to use the word "Duke"
and its logo in identifying our businesses. This right may be terminated by Duke
Energy at its sole option any time after:

- Duke Energy's direct or indirect ownership interest in our company is
less than or equal to 35%; or

- Duke Energy no longer controls, directly or indirectly, the management
and policies of our company.

Following the receipt of Duke Energy's notice of termination, we have
agreed to amend our organizational documents and those of our subsidiaries to
remove the "Duke" name and to phase out within 180 days of the date of the
notice the use of existing signage, printed literature, sales materials and
other materials bearing a name, phrase or logo incorporating "Duke."

TRANSACTIONS PRIOR TO THE COMBINATION

Transactions between Duke Energy and Phillips' midstream natural gas
business. Prior to the Combination, Duke Energy and its subsidiaries engaged in
a number of transactions with the subsidiaries of Phillips that were transferred
to us in the Combination, including GPM Gas Corporation (the "Phillips Combined
Subsidiaries"). These transactions were entered into in the ordinary course of
Duke Energy's and the Phillips Combined Subsidiaries' business and were related
to the purchase and sale of raw natural gas, residue gas and NGLs at market
prices.

Transactions between Duke Energy and the Predecessor Company. Prior to the
Combination, Duke Energy and its subsidiaries engaged in a number of
transactions with the Predecessor Company. The following is a description of
those transactions.

The Predecessor Company historically sold a portion of its residue gas and
NGLs to Duke Energy and its subsidiaries, including Duke Energy Trading and
Marketing, at contractual prices that approximated market prices. The
Predecessor Company's revenues from such sales were approximately $567.8 million
in 1997, $536.3 million in 1998 and $696.7 million in 1999. We anticipate that
we will continue to sell residue gas and NGLs to Duke Energy and its
subsidiaries (including Duke Energy Trading and Marketing) at market prices in
the ordinary course of our business.

The Predecessor Company historically purchased residue gas from Duke Energy
and its subsidiaries at contractual prices that approximated market prices. The
Predecessor Company's purchases of raw natural gas and other petroleum products
from Duke Energy and its subsidiaries totaled $48.9 million in 1997, $79.6
million in 1998 and $128.6 million in 1999. We anticipate that we will continue
to purchase residue gas and other petroleum products at market prices from Duke
Energy and its subsidiaries in the ordinary course of our business.

The Predecessor Company historically provided gathering and transportation
services over its gathering systems and pipelines to Duke Energy and its
subsidiaries at market prices. The Predecessor Company generated no revenues in
1997, $6.4 million in 1998 and $2.7 million in 1999 from the provision of such
services. We anticipate that we will continue to provide gathering and
transportation to Duke Energy and its subsidiaries at market prices in the
ordinary course of our business.

Duke Energy has historically provided the Predecessor Company with various
support services, including information technology services, accounting, legal,
insurance, payroll, cash management, risk management and welfare benefits
services. Duke Energy has historically billed the Predecessor Company for such
services at prices that approximate their cost to provide such services. The
Predecessor Company was charged $11.7 million in 1997, $12.1 million in 1998 and
$19.1 million in 1999 for such services. Duke will continue to provide some of
these services under the terms of the Services Agreement described above.

On June 30, 1995, the Predecessor Company issued a $101.6 million note to
Duke Energy. The note is scheduled to mature in 2004 and bears interest at 8.5%.
In addition, on December 31, 1996, the Predecessor Company issued a $540 million
note to Duke Energy. The note matured at the end of each year and was

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extended for subsequent one year periods at each year end. The note bears
interest at prime rate, adjusted quarterly.

TRANSACTIONS WITH PHILLIPS

SERVICES AGREEMENT

We have entered into a Services Agreement with Phillips, effective March
, 2000. Under this agreement, Phillips will provide us with various
staff and support services, including information technology products and
services, cash management, real estate and property tax services. The above
services are priced on the basis of a monthly charge equal to Phillips'
fully-burdened cost of providing the services. This agreement expires on
December 31, 2000 unless renewed by the mutual agreement by the parties.

TRANSACTIONS PRIOR TO THE COMBINATION

Transactions between Phillips and Duke Energy's midstream natural gas
business. Prior to the Combination, Phillips engaged in a number of transactions
with the Predecessor Company. These transactions were entered into in the
ordinary course of Phillips' and the Predecessor Company's business and were
related to the purchase and sale of raw natural gas, residue gas and NGLs at
market prices.

Transactions between Phillips and its midstream natural gas business. Prior
to the Combination, Phillips engaged in a number of transactions with GPM Gas
Corporation. The following is a description of those transactions.

Long-Term NGLs Purchase Contract. GPM Gas Corporation, the subsidiary of
Phillips that owned its midstream natural gas assets that were contributed to us
in the Combination, and Phillips 66 Company, a division of Phillips, entered
into an NGL Output Purchase and Sale Agreement effective as of January 1, 2000.
The agreement allows Phillips 66 Company to purchase at index-based prices
approximately all of the NGLs produced by the processing plants owned by GPM Gas
Corporation prior to the Combination. The 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 us in the
future in various counties in the Mid-Continent and Permian Basin regions and
the Austin Chalk area. The agreement has a 15-year primary term and a four-year
phase-down period. The agreement prohibits us from modifying our normal business
practices to divert or reduce NGLs available for purchase by Phillips 66 Company
from current delivery levels.

GPM Gas Corporation historically sold a portion of its residue gas and
other by-products to Phillips at contractual prices that approximated market
prices. In addition, GPM Gas Corporation sold NGLs to Phillips at prices based
upon quoted market prices for fractionated NGLs, less transportation,
fractionation and quality-adjustment fees. GPM Gas Corporation's operating
revenues from the sale of residue gas, other by-products and NGLs to Phillips
were approximately $758.7 million in 1997, $537.5 million in 1998 and $725.5
million in 1999. We anticipate that we will continue to sell residue gas and
NGLs to Phillips and its subsidiaries or co-venturers at market prices in the
ordinary course of our business, including in connection with our long term
contract with Phillips described above.

The Phillips Combined Subsidiaries historically purchased raw natural gas
from Phillips at contractual prices that approximated market prices. The
Phillips Combined Subsidiaries' purchases of raw natural gas from Phillips
totaled $118.8 million in 1997, $76.6 million in 1998 and $100.3 million in
1999. We anticipate that we will continue to purchase raw natural gas from
Phillips at market prices in the ordinary course of our business.

Phillips historically provided the Phillips Combined Subsidiaries with
various field services and other general administrative services including
insurance, personnel administration, employee benefits, office space,
communications, data processing, engineering, automotive and other field
equipment, and other miscellaneous services, including legal, treasury,
planning, tax, auditing and other corporate services. These services were priced
to reimburse Phillips for its actual costs to provide the services. Charges for
these services and benefits

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were $12.1 million in 1997, $12.1 million in 1998 and $11.4 million in 1999.
These services were terminated upon consummation of the Combination.

Phillips 66 Company, a division of Phillips, has historically purchased
sulfur from GPM Gas Corporation pursuant to an agreement for sulfur sales that
is renewed annually. Phillips 66 Company's purchases of sulfur from GPM Gas
Corporation totaled $446,000 in 1997, $412,000 in 1998 and $1.1 million in 1999.
Phillips 66 Company will continue to purchase sulfur from GPM Gas Corporation
pursuant to the terms of the agreement currently in effect.

Prior to the Combination, all operational and personnel requirements of the
Phillips Combined Subsidiaries were met by Phillips' employees. All services
provided by Phillips were priced to cover the actual costs of these services,
which equaled $76.6 million in 1997, $74.8 million in 1998 and $74.9 million in
1999. These services were terminated when we hired most of the employees of the
Phillip Combined Subsidiaries.

The Phillips Combined Subsidiaries earned interest of $2.7 million in 1997,
$2.4 million in 1998 and $2.5 million in 1999 from participation in Phillips'
centralized cash management system. Participation in the system was terminated
upon the completion of the Combination.

Phillips Gas Company had long-term borrowings from Phillips and other
liabilities outstanding to Phillips of $655.0 million at the end of 1997, $560.0
million at the end of 1998 and $1,350.0 million at the end of 1999. Phillips Gas
Company incurred interest expense of $20.3 million in 1997, $35.9 million in
1998 and $35.6 million in 1999 on these borrowings. Included in the $1,350.0
million of borrowings outstanding at the end of 1999 is a $780.0 million
dividend from Phillips Gas Company to Phillips in the form of a note payable.
These borrowings from Phillips were paid at the closing of the Combination.

The Phillips Combined Subsidiaries historically provided Phillips with
other minor administrative services. Costs allocated to Phillips for these
services were $120,000 in 1997, $79,000 in 1998 and $72,000 in 1999. These
services were terminated upon the consummation of the Combination.

The Phillips Combined Subsidiaries periodically bought from, or sold to,
Phillips various assets in the operation of its business. These net acquisitions
totaled $22,000 in 1997, $60,000 in 1998 and $239,000 in 1999.

SHAREHOLDERS AGREEMENT

Immediately prior to the consummation of the offerings, Duke Energy Natural
Gas Corporation, the subsidiary of Duke Energy that will hold all of Duke
Energy's shares of our common stock, and Phillips will enter into a shareholders
agreement covering the matters discussed below. The shareholders agreement will
terminate on the first date that either of Duke Energy or Phillips owns less
than 20% of our outstanding common stock. Duke Energy and Phillips have agreed
to cause each of their subsidiaries that hold shares of our common stock to
execute the shareholders agreement and to comply with the obligations of the
parties to the shareholders agreement.

ELECTION OF DIRECTORS

Each of Duke Energy and Phillips will agree to vote its shares of common
stock to elect seven directors designated by Duke Energy, so long as Duke Energy
owns at least 30% of our outstanding common stock, and four directors designated
by Phillips, so long as Phillips owns at least 20% of our outstanding common
stock. If Duke Energy owns less than 30% but at least 20% of our outstanding
common stock, the number of Duke Energy designees elected will be
proportionately reduced and the number of Phillips designees elected will be
proportionately increased. The shareholders agreement requires that Duke Energy
and Phillips together include in their director designees a total of three
individuals who are not officers, directors or employees of Duke Energy,
Phillips or any of their affiliates. Initially, Duke Energy will designate two
of these independent directors, and Phillips will designate one.

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SPECIAL BUYOUT RIGHT

After the first anniversary of the completion of the offerings, Duke Energy
will have the right to acquire all of the common stock owned by Phillips at an
appraised fair market value of such shares if, on three separate occasions,
certain specified actions (which are described in the first five bullet points
under "Description of Capital Stock -- Supermajority Requirements") have failed
to receive the approval of our Board of Directors. Duke Energy will be entitled
to exercise this right only if each of its directors designated and none of
Phillips' designated directors voted in favor of such actions.

RIGHT OF FIRST REFUSAL

If Duke Energy or Phillips desires to sell all or any portion of its shares
of our common stock (other than pursuant to a registered public offering), the
non-selling party will have a right of first refusal to purchase all (but not
less than all) of the shares that the selling party desires to transfer, on the
same terms and conditions as those set forth in the notice of the proposed
transfer.

CHANGE OF CONTROL

If Duke Energy or Phillips or any of their affiliates, which hold our
common stock, undergoes a specified type of change of control, the other party
will have the right to purchase the shares in our company owned by the entity
experiencing the change of control at an appraised fair market value of such
shares.

REGISTRATION RIGHTS AGREEMENT

Upon completion of the offerings, we will enter into a registration rights
agreement with Duke Energy and Phillips. This agreement will give each of Duke
Energy and Phillips the right, on two occasions, to demand that we register all
or any portion of their shares of our common stock for sale under the Securities
Act. However, any demand to register shares must cover at least 3% of the common
stock then outstanding. Further, if we propose to register any of our common
stock under the Securities Act, Duke Energy and Phillips will have the right to
include their shares of common stock in the registration subject to certain
limitations. Despite a registration demand by either Duke Energy or Phillips, we
may delay registering their shares of our common stock for a reasonable time not
to exceed 180 days if, in the judgment of our Board, filing the registration
would require the disclosure of pending or contemplated matters or information
which would:

- likely be detrimental to our company;

- materially interfere with our business; or

- materially interfere with a pending or contemplated material transaction.

We have agreed to cooperate fully in connection with any such registration
and with any offering made pursuant to such registration. In addition, we have
agreed to pay all costs and expenses (other than fees, discounts and commissions
of underwriters, brokers and dealers; capital gains, income and transfer taxes
(if any); and the fees and disbursements of counsel to Duke Energy or Phillips)
related to the registration and sale of shares of our common stock by Duke
Energy or Phillips in any registered offering. The rights of Duke Energy and
Phillips under the registration rights agreement are assignable under certain
circumstances. The rights of each of Duke Energy and Phillips under the
registration rights agreement terminate at any time when they and their
affiliates own less than 10% of our outstanding common stock.

CONFLICTS OF INTEREST

Generally, directors and officers have a fiduciary duty to manage their
company in a manner beneficial to the company and its stockholders. The majority
of our directors and officers are either current or former directors or officers
of Duke Energy or Phillips, and two of our officers are directors of the general
partner of TEPPCO. In certain circumstances, an action beneficial to Duke
Energy, Phillips or TEPPCO may be detrimental to our interests. Given certain
shared directors and officers these circumstances may create

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conflicts of interest. Additionally, our extensive relationships with Duke
Energy and Phillips also may result in conflicts of interest.

In order to mitigate potential conflicts of interest, as long as Duke
Energy and Phillips each own at least 20% of our voting stock, any future
transactions between our company and Duke Energy, Phillips or any of their
affiliates, which are on terms that are clearly less favorable terms than those
that are within the range of comparable transactions between unaffiliated third
parties, must be approved by 8 of our 11 directors.

PRINCIPAL STOCKHOLDERS

The following table sets forth information regarding the beneficial
ownership of our common stock, after the offerings, by:

- each holder of more than 5% of our common stock;

- our Chief Executive Officer and each of our next five most highly
compensated executive officers;

- each director and director nominee; and

- all directors and executive officers as a group.

The exact allocation of shares of common stock between Duke Energy and Phillips
will be determined based on the average of the closing prices of our common
stock on the New York Stock Exchange Composite Tape on its first five trading
days. For purposes of the table set forth below the number of shares of common
stock to be beneficially owned by each of Duke Energy and Phillips has been
estimated based upon an assumed initial public offering price of $ . Unless
otherwise stated in the notes to the table, each of the stockholders has sole
voting and investment power with respect to the shares of common stock
beneficially owned by him.

<TABLE>
<CAPTION>
BENEFICIALLY OWNED
AFTER THE OFFERINGS
---------------------
NAME OF BENEFICIAL OWNERS SHARES PERCENTAGE
- ------------------------- -------- ----------
<S> <C> <C>
Duke Energy Corporation..................................... %
526 South Church Street
Charlotte, North Carolina 28201-1006
Phillips Petroleum Company..................................
Phillips Building
Bartlesville, Oklahoma 74004
Jim W. Mogg.................................................
Michael J. Panatier.........................................
Mark A. Borer...............................................
Michael J. Bradley..........................................
David D. Frederick..........................................
Robert F. Martinovich.......................................
William J. Slaughter........................................
Martha B. Wyrsch............................................
Fred J. Fowler..............................................
J.J. Mulva..................................................
Richard B. Priory...........................................
All directors and executive officers as a group
( persons)...............................................
</TABLE>

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

* Less than 1%.

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DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of shares of common stock,
par value $.01 per share, and shares of preferred stock, par value
$.01 per share.

COMMON STOCK

Following the offerings, shares of common stock will be issued
and outstanding. Holders of our common stock are entitled to one vote per share
on all matters to be voted upon by the stockholders. Holders of common stock do
not have cumulative voting rights. As a result, the holders of a majority of the
shares of our common stock can elect all of the members of the Board of
Directors, subject to the rights, powers and preferences of any outstanding
series of preferred stock. Subject to preferences of any preferred stock that
may be issued, the holders of our common stock are entitled to receive such
dividends as may be declared by the Board of Directors. The common stock is
entitled to receive pro rata all of our assets available for distribution to our
stockholders in liquidation, subject to the rights and preferences of any
outstanding series of preferred stock. There are no redemption or sinking fund
provisions applicable to the common stock. All outstanding shares of common
stock are fully paid and non-assessable.

PREFERRED STOCK

Subject to the provisions of the certificate of incorporation and
limitations prescribed by law, our Board of Directors has the authority to issue
up to shares of preferred stock in one or more series and to fix the
rights, preferences, privileges and restrictions thereof, including dividend
rights and rates, conversion rates, voting rights, redemption terms and prices,
liquidation preferences and the number of shares constituting any series or the
designation of such series, which may be superior to those of the common stock,
without further vote or action by the stockholders.

The issuance of shares of preferred stock pursuant to the Board of
Directors' authority described above may adversely affect the rights of the
holders of our common stock. For example, preferred stock may rank prior to the
common stock with respect to dividend rights, liquidation preference or both,
may have full or limited voting rights and may be convertible into shares of
common stock. Accordingly, the issuance of shares of preferred stock may
discourage bids for our common stock or may otherwise adversely affect the
market price of our common stock. In addition, the preferred stock may enable
our Board of Directors to render more difficult or to discourage attempts by
others to obtain control of our company through a tender offer, proxy contest,
merger or otherwise.

ANTI-DILUTION RIGHTS

If we sell shares of our common stock or shares of any other previously
issued and outstanding capital stock in a public offering (other than pursuant
to an employee compensation or benefit plan or program approved by our Board of
Directors in accordance with our bylaws), our certificate of incorporation
provides that Duke Energy and Phillips each have the right to purchase the
amount of the offering necessary to maintain their ownership percentages in that
class of securities. In order to exercise this right, Duke Energy or Phillips
must each own, directly or indirectly, at least 20% of all outstanding shares of
our common stock.

ANTI-TAKEOVER PROVISIONS OF OUR CERTIFICATE OF INCORPORATION AND BYLAWS

Our certificate of incorporation and bylaws contain several provisions that
could delay or make more difficult the acquisition of us through a hostile
tender offer, open market purchases, proxy contest, merger or otherwise.

WRITTEN CONSENT OF STOCKHOLDERS

Our certificate of incorporation provides that, on and after the date when
Duke Energy ceases to own (directly or indirectly) a majority of the shares of
our outstanding securities entitled to vote in the election of directors, any
action by our stockholders must be taken at an annual or special meeting of
stockholders. Until

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that date, any action required or permitted to be taken by our stockholders may
be taken at a duly called meeting of stockholders or by the written consent of
stockholders owning the minimum number of shares required to approve the action.

SPECIAL MEETINGS OF STOCKHOLDERS

Subject to the rights of the holders of any series of preferred stock
approved by our Board of Directors, special meetings of the stockholders may
only be called by the Chairman of the Board of Directors or by the resolution of
a majority of our Board of Directors.

ADVANCE NOTICE PROCEDURE FOR DIRECTOR NOMINATIONS AND STOCKHOLDER PROPOSALS

Our bylaws establish advance notice procedures for the nomination of
candidates for election as directors as well as for stockholder proposals to be
considered at annual meetings of stockholders. Notice of a stockholder's intent
to nominate a director must be received at our principal executive offices as
follows:

- with respect to an election to be held at the annual meeting of
stockholders, not later than 90 days nor earlier than 120 days prior to
the anniversary date of the immediately preceding annual meeting of
stockholders; and

- with respect to an election to be held at a special meeting of
stockholders, not later than the later of (1) 90 days prior to the
special meeting or (2) 10 days following the public announcement of the
special meeting, nor earlier than 120 days before the special meeting.

Notice of a stockholder's intent to raise business at an annual meeting
must be received at our principal executive offices not later than 90 days nor
earlier than 120 days prior to the anniversary date of the preceding annual
meeting of stockholders.

These procedures may operate to limit the ability of stockholders to bring
business before a stockholders meeting, including the nomination of directors or
considering any transaction that could result in a change in control.

LIMITATION OF BUSINESS OPPORTUNITIES

We have added provisions to our certificate of incorporation that limit the
scope of our business and provide that Duke Energy and its affiliates may engage
in the midstream gas gathering, processing, marketing and transportation
businesses, even if those businesses have a competitive impact on us. In
general, Duke Energy is permitted to engage in any business, including
businesses in competition with us, provided:

- the business opportunity is not identified through the disclosure of
information by or on behalf of our company or as a direct result of a
person's service as an officer or director of our company; and

- the business is developed and pursued solely through Duke Energy's own
personnel and not through us.

If an opportunity in the midstream natural gas gathering, processing,
marketing and transportation industry is presented to a person who is an officer
or director of both Duke Energy and our company, Duke Energy has no obligation
to communicate or offer the opportunity to us and may pursue the opportunity as
it sees fit, unless it was presented to that person solely in, and as a direct
result of, that person's service as a director or officer of our company.

The purpose clause of our certificate of incorporation permits us to engage
only in the midstream natural gas gathering, processing, marketing and
transportation businesses in the United States and Canada and the marketing of
NGLs in Mexico. We may engage in other activities with the approval of eight of
the eleven members of our Board and, so long as Duke Energy owns, directly or
indirectly, a majority of our common stock or otherwise controls our company,
the approval of Duke Energy in its sole discretion. We cannot amend our
certificate of incorporation to expand our purpose clause without Duke Energy's
prior written consent.

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AMENDMENT OF THE BYLAWS

Our certificate of incorporation and bylaws provide that the Board of
Directors may amend or repeal the bylaws and adopt new bylaws. Our bylaws
provide that the holders of common stock may amend or repeal the bylaws and
adopt new bylaws by a majority vote. However, so long as each of Duke Energy and
Phillips owns (directly or indirectly) at least 20% of our voting stock, any
amendment or repeal of, or adoption of any new bylaw inconsistent with, certain
of our bylaws relating to our Board of Directors (including supermajority
approval requirements) and the amendments of our bylaws must be approved by each
of Duke Energy and Phillips.

LIMITATION OF LIABILITY OF OFFICERS AND DIRECTORS

Our certificate of incorporation provides that no director shall be
personally liable to our company or our stockholders for monetary damages for
breach of fiduciary duty as a director, except for liability as follows:

- for any breach of the director's duty of loyalty to our company or our
stockholders;

- for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of law;

- for unlawful payment of a dividend or unlawful stock purchase or
redemption; and

- for any transaction from which the director derived an improper personal
benefit.

These provisions eliminate the rights of our company and our stockholders,
through stockholders' derivative suits on our behalf, to recover monetary
damages against a director for breach of fiduciary duty as a director, including
breaches resulting from grossly negligent behavior, except in the situations
described above.

DELAWARE ANTI-TAKEOVER STATUTE

Under the terms of our certificate of incorporation and as permitted under
Delaware law, we have elected not to be governed by Delaware's anti-takeover
law. This law provides that specified persons who, together with affiliates and
associates, own, or within three years did own, 15% or more of the outstanding
voting stock of a corporation may not engage in certain business combinations
with the corporation for a period of three years after the date on which the
person became an interested stockholder. The law defines the term "business
combination" to encompass a wide variety of transactions with or caused by an
interested stockholder, including mergers, asset sales and other transactions in
which the interested stockholder receives or could receive a benefit on other
than a pro rata basis with other stockholders. With the approval of our
stockholders, we may amend our certificate of incorporation in the future to
become governed by the anti-takeover law. This provision would then have an
anti-takeover effect for transactions not approved in advance by our Board of
Directors, including discouraging takeover attempts that might result in a
premium over the market price for the shares of our common stock. By opting out
of the Delaware anti-takeover law, a transferee of Duke Energy or Phillips could
pursue a takeover transaction that was not approved by our Board of Directors.

SUPERMAJORITY REQUIREMENTS

Our bylaws require the approval of at least eight of the eleven directors
elected by Duke Energy and Phillips for any of the following:

- entering a new line of business outside of the midstream natural gas
gathering, processing, marketing and transportation businesses (and
directly related activities) in the United States and Canada;

- approval of any merger, consolidation, recapitalization, acquisition,
divestiture, joint venture or alliance (or a related series of such
transactions) involving the acquisition or expenditure (in the form of
cash or otherwise) of more than $200 million in value to or from the
company;

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<PAGE> 72

- entering into any sales contract or commitment that has a term of five
years or more and that involves annual revenues to the company of more
than 5% of the company's total annual sales revenues for the most
recently completed fiscal year;

- any capital expenditure in excess of $200 million;

- any borrowing in excess of $200 million;

- approval of any shut-down of a facility having a fair market value of
more than $100 million;

- any liquidation or dissolution of the company;

- changing auditors;

- settlement of actions or claims against us involving payment by us of
more than $25 million, excluding amounts covered or reimbursed by
insurance;

- entering into transactions with either Duke Energy, Phillips or any of
their affiliates on terms that are clearly less favorable than those
terms that are within the range of comparable transactions between
unaffiliated third parties; and

- approval of compensation policies for employees, including specific
compensation and benefit plans and programs, to the extent such policies
are of the type that would customarily be considered by a compensation
committee of the board of directors of a comparably sized,
publicly-traded corporation.

As long as each of Duke Energy and Phillips owns (directly or indirectly) at
least 20% of our voting stock, these provisions of the bylaws may not be amended
or changed without the consent of both Duke Energy and Phillips. The
requirements of super-majority approval for these actions will terminate when
the ownership interest of either Duke Energy or Phillips is less than 20%.

Since these governance procedures require more than a majority vote of the
Board of Directors to approve a merger or consolidation, this may make any
merger or consolidation more difficult.

LISTING

We intend to file an application for our common stock to be quoted on the
New York Stock Exchange under the symbol "DEF."

TRANSFER AGENT AND REGISTRAR

The Transfer Agent and Registrar for our common stock is Duke Energy.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to the offerings, there was no public market for our common stock.
Future sales of substantial amounts of our common stock in the public market
could adversely affect the market price of our common stock. After the offerings
is completed, the number of shares available for future sale into the public
markets will be subject to legal and contractual restrictions, some of which are
described below. The lapsing of these restrictions will permit sales of
substantial amounts of our common stock in the public market or could create the
perception that such sales could occur, which could adversely affect the market
price for our common stock. These factors could also make it more difficult for
us to raise funds through the future offering of common stock.

After the offerings, shares of our common stock will be
outstanding. Of these shares, the shares sold in the offering will be
freely transferable and may be sold without restriction or further registration
under the Securities Act, except for any shares acquired by our "affiliates" as
defined in Rule 144 under the Securities Act. The remaining shares of
common stock outstanding and owned by Duke Energy and Phillips will be subject
to the lock-up agreements described below for 180 days after which they may be
sold in the future without registration under the Securities Act to the extent
permitted by Rule 144, as described below, or any applicable exemption under the
Securities Act. In addition, shares owned by Duke Energy and Phillips may be
registered for sale under the Securities Act under the terms of the registration
rights agreement with us.

RULE 144

Under Rule 144 beginning 90 days after the date of this prospectus, a
person, or persons whose shares are aggregated, who has beneficially owned
"restricted securities" for at least one year would be entitled to sell within
any three-month period a number of shares that does not exceed the greater of:

- 1% of the number of shares of common stock then outstanding, which will
equal approximately shares immediately after the offering; and

- the average weekly trading volume of the common stock on the New York
Stock Exchange during the four calendar weeks preceding the filing of a
notice on Form 144 with respect to such sale with the SEC.

Sales under Rule 144 are also subject to certain other requirements regarding
the manner of sale, notice and availability of current public information about
us.

Under Rule 144(k), a person who is not deemed to have been one of our
"affiliates" at any time during the 90 days preceding a sale, and who has
beneficially owned the shares proposed to be sold for at least two years
(including the holding period of any prior owner other than an affiliate) is
entitled to sell such shares without complying with the manner of sale, public
information, volume limitation or notice provisions of Rule 144.

Because Duke Energy and Phillips are among our affiliates, subject to
exercise of their registration rights described under "Relationship with Duke
Energy and Phillips -- Registration Rights Agreement," the Rule 144 restrictions
and requirements would be applicable to Duke Energy's and Phillips' shares for
as long as they retain affiliate status.

LOCK-UP AGREEMENTS

In connection with the offerings, we, Duke Energy and Phillips have agreed
not to directly or indirectly engage in the following activities for a period of
180 days after the date of this prospectus without the prior written consent of
Morgan Stanley & Co. Incorporated:

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indirectly, any shares of common stock or securities convertible into or
exchangeable or exercisable for common stock; or

- enter into any swap or other arrangement that transfers to another, in
whole or in part, any of the economic consequence of ownership of common
stock whether any such swap or transaction is to be settled by delivery
of common stock or other securities, in cash or otherwise.

As exceptions to these restrictions, we may:

- issue shares of our common stock or grant options to purchase shares of
common stock pursuant to our existing employee benefit plans;

- issue shares of our common stock pursuant to any non-employee director
stock plan; and

- issue shares of our common stock or securities convertible or
exchangeable into our common stock as payment of any part of the purchase
price for businesses or assets we acquire; however, shares issued in this
manner may not be transferred during the 180-day lock-up period.

2000 LONG-TERM INCENTIVE PLAN

After the offerings, we intend to file a registration statement covering
the sale of approximately shares of common stock reserved for issuance
under our long-term incentive plan thus permitting resale of these shares by
non-affiliates in the public market without restriction.

MATERIAL UNITED STATES FEDERAL TAX CONSEQUENCES
TO NON-UNITED STATES HOLDERS OF COMMON STOCK

The following is a general discussion of the material U.S. federal income
and estate tax considerations with respect to the ownership and disposition of
common stock applicable to Non-U.S. Holders. In general, a "Non-U.S. Holder" is
any beneficial owner of common stock other than

- a citizen or resident of the United States,

- a corporation, partnership or other entity created or organized in the
United States or under the laws of the United States or of any state
thereof,

- an estate, the income of which is includible in gross income for U.S.
federal income tax purposes regardless of its source, or

- a trust whose administration is subject to the primary supervision of a
United States court and which has one or more United States persons who
have the authority to control all substantial decisions of the trust.

This discussion is based on current provisions of the Internal Revenue
Code, Treasury Regulations promulgated under the Internal Revenue Code, judicial
opinions, published positions of the Internal Revenue Service, and all other
applicable authorities, all of which are subject to change, possibly with
retroactive effect. This discussion does not address all aspects of income and
estate taxation or any aspects of state, local, or non-U.S. taxes, nor does it
consider any specific facts or circumstances that may apply to a particular
Non-U.S. Holder that may be subject to special treatment under the U.S. federal
income tax laws, such as insurance companies, tax-exempt organizations,
financial institutions, brokers, dealers in securities, and U.S. expatriates.

Prospective investors are urged to consult their tax advisors regarding the
U.S. federal, state, local and non-U.S. income and other tax considerations of
acquiring, holding and disposing of shares of common stock.

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DIVIDENDS

In general, dividends paid to a Non-U.S. Holder will be subject to U.S.
withholding tax at a 30% rate of the gross amount, or a lower rate prescribed by
an applicable income tax treaty, unless the dividends are effectively connected
with a trade or business carried on by the Non-U.S. Holder within the United
States. Dividends that are effectively connected with such a U.S. trade or
business generally will not be subject to U.S. withholding tax if the Non-U.S.
Holder files the required forms, including Internal Revenue Service Form 4224,
Form W-8ECI, or any successor form, with the payor of the dividend, and
generally will be subject to U.S. federal income tax on a net income basis, in
the same manner as if the Non-U.S. Holder were a resident of the United States.
An applicable treaty may also require the dividends to be attributable to a
permanent establishment in the United States to be subject to United States
taxes. A Non-U.S. Holder that is a corporation may be subject to an additional
branch profits tax at a rate of 30%, or such lower rate as may be specified by
an applicable income tax treaty, on the repatriation from the United States of
its "effectively connected earnings and profits," subject to adjustments. To
determine the applicability of a tax treaty providing for a lower rate of
withholding under the currently effective Treasury Regulations, dividends paid
to an address in a foreign country are presumed to be paid to a resident of that
country absent knowledge to the contrary. Under Treasury Regulations (the "Final
Regulations") generally effective for payments made after December 31, 2000,
however, a Non-U.S. Holder will be required to satisfy certification
requirements in order to claim a reduced rate of withholding under an applicable
income tax treaty. In addition, under the Final Regulations, in the case of
common stock held by a foreign partnership, the certification requirement would
generally be applied to the partners of the partnership (unless the partnership
agrees to become a "withholding foreign partnership") and the partnership would
be required to provide certain information. The Final Regulations also provide
"look-through" rules for tiered partnerships.

A Non-U.S. Holder of common stock that is eligible for a reduced rate of
U.S. federal income tax withholding pursuant to a tax treaty may obtain a refund
of any excess amounts withheld by filing an appropriate claim for refund with
the Internal Revenue Service.

GAIN ON SALE OR OTHER DISPOSITION OF COMMON STOCK

In general, a Non-U.S. Holder will not be subject to U.S. federal income
tax on any gain realized upon the sale or other taxable disposition of the
holder's shares of common stock so long as:

- the gain is not effectively connected with a trade or business carried on
by the Non-U.S. Holder within the United States;

- if the Non-U.S. Holder is an individual, the Non-U.S. Holder holds shares
of common stock as a capital asset, is not present in the United States
for 183 days or more in the taxable year of disposition or does not have
a "tax home" in the United States for U.S. federal income tax purposes
and meets certain other requirements;

- the Non-U.S. Holder is not subject to tax under the provisions of the
Internal Revenue Code regarding the taxation of U.S. expatriates; and

- the common stock continues to be "regularly traded on an established
securities market" for U.S. federal income tax purposes and the Non-U.S.
Holder has not held, directly or indirectly, at any time during the
five-year period ending on the date of disposition (or, if shorter, the
Non-U.S. Holder's holding period) more than five percent of the
outstanding common stock.

ESTATE TAX

Common stock owned or treated as owned by an individual who is not a
citizen or resident, as defined for U.S. federal estate tax purposes, of the
United States at the time of death will be includible in the individual's gross
estate for U.S. federal estate tax purposes, unless an applicable estate tax
treaty provided otherwise, and therefore may be subject to U.S. federal estate
tax.

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BACKUP WITHHOLDING, INFORMATION REPORTING AND OTHER REPORTING REQUIREMENTS

The Company must report annually to the Internal Revenue Service and to
each Non-U.S. Holder the amount of dividends paid to, and the tax withheld with
respect to, each Non-U.S. Holder. These reporting requirements apply regardless
of whether withholding was reduced or eliminated by an applicable tax treaty.
Copies of this information also may be made available under the provisions of a
specific treaty or agreement with the tax authorities in the country in which
the Non-U.S. Holder resides or is established.

Under current law, U.S. backup withholding tax (which generally is imposed
at the rate of 31% on applicable payments to persons that fail to furnish the
information required under the U.S. information reporting requirements) and
information reporting requirements generally will not apply to dividends paid on
common stock to a Non-U.S. Holder at an address outside the United States.
Backup withholding and information reporting generally will apply, however, to
dividends paid on shares of common stock to a Non-U.S. Holder at an address in
the United States if the holder fails to establish an exemption or to provide
certification of its non-U.S. status and other required information to the
payor.

Under current law, the payments of proceeds from the disposition of common
stock to or through a U.S. office of a broker will be subject to information
reporting and backup withholding, unless the beneficial owner, under penalties
of perjury, certifies, among other things, its status as a Non-U.S. Holder or
otherwise establishes an exemption. The payment of proceeds from the disposition
of common stock to or through a non-U.S. office of a broker generally will not
be subject to backup withholding and information reporting, except as noted
below. In the case of proceeds from a disposition of common stock paid to or
through a non-U.S. office of a broker that is

- a U.S. person,

- a "controlled foreign corporation" for U.S. federal income tax purposes,
or

- a foreign person 50% or more of whose gross income from a specified
period is effectively connected with a U.S. trade or business,

information reporting, but not backup withholding, will apply unless the broker
has documentary evidence in its files that the owner is a Non-U.S. Holder and
other conditions are satisfied, or the beneficial owner otherwise establishes an
exemption, and the broker has no actual knowledge to the contrary.

Under the Final Regulations, the payment of dividends or the payment of
proceeds from the disposition of common stock to a Non-U.S. Holder may be
subject to information reporting and backup withholding unless the recipient
satisfies the certification requirements of the Final Regulations by proving its
non-U.S. status or otherwise establishes an exemption. Under the Final
Regulations, the sale of common stock outside of the U.S. through a non-U.S.
broker will also be subject to information reporting if the broker is a foreign
partnership and at any time during its tax year:

- one or more of its partners are United States persons, as described in
United States Treasury regulations, who in the aggregate hold more than
50% of the income or capital interests in the partnership, or

- the foreign partnership is engaged in a U.S. trade or business.

Backup withholding is not an additional tax. Any amounts withheld under the
backup withholding rules from a payment to a Non-U.S. Holder can be refunded or
credited against the Non-U.S. Holder's U.S. federal income tax liability, if
any, provided that the required information is furnished to the Internal Revenue
Service in a timely manner.

Each prospective Non-U.S. Holder of common stock should consult that
holder's own tax adviser with respect to the federal, state, local and foreign
tax consequences of the acquisition, ownership and disposition of common stock.

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UNDERWRITERS

GENERAL

Under the terms and subject to the conditions contained in an underwriting
agreement dated the date of this prospectus the U.S. underwriters named below,
for whom Morgan Stanley & Co. Incorporated, Merrill Lynch, Pierce, Fenner &
Smith Incorporated, Banc of America Securities LLC, Lehman Brothers Inc., J.P.
Morgan Securities Inc., PaineWebber Incorporated and Petrie Parkman & Co. are
acting as U.S. representatives, and the international underwriters named below
for whom Morgan Stanley & Co. International Limited and Merrill Lynch
International are acting as international representatives, have severally agreed
to purchase, and Duke Energy Field Services Corporation has agreed to sell to
them, severally, the number of shares indicated below:

<TABLE>
<CAPTION>
NUMBER OF
NAME SHARES
- ---- ---------
<S> <C>
U.S. Underwriters:
Morgan Stanley & Co. Incorporated......................
Merrill Lynch, Pierce, Fenner & Smith
Incorporated..............................
Banc of America Securities LLC ........................
Lehman Brothers Inc. ..................................
J.P. Morgan Securities Inc. ...........................
PaineWebber Incorporated...............................
Petrie Parkman & Co. ..................................
--------
Subtotal...............................................
========
International Underwriters:
Morgan Stanley & Co. International Limited.............
Merrill Lynch International............................
--------
Subtotal...............................................
Total..............................................
========
</TABLE>

The U.S. underwriters and the international underwriters, and the U.S.
representatives and the international representatives, are collectively referred
to as the "underwriters" and the "representatives," respectively. The
underwriters are offering the shares of common stock subject to their acceptance
of the shares from Duke Energy Field Services Corporation and subject to prior
sale. The underwriting agreement provides that the obligations of the several
underwriters to pay for and accept delivery of the shares of common stock
offered by this prospectus are subject to the approval of certain legal matters
by their counsel and to certain other conditions. The underwriters are obligated
to take and pay for all of the shares of common stock offered by this prospectus
if any such shares are taken. However, the underwriters are not required to take
or pay for the shares covered by the underwriters over-allotment option
described below.

In the agreement between U.S. and international underwriters, sales may be
made between U.S. underwriters and international underwriters of any number of
shares as may be mutually agreed. The per share price of any shares sold by the
underwriters shall be the public offering price listed on the cover page of this
prospectus, in United States dollars, less an amount not greater than the per
share amount of the concession to dealers described below.

The underwriters initially propose to offer part of the shares of common
stock directly to the public at the public offering price listed on the cover
page of this prospectus and part to certain dealers at a price that represents a
concession not in excess of $ a share under the public offering price. Any
underwriter may allow, and such dealers may reallow, a concession not in excess
of $ a share to other underwriters or to certain dealers. After the initial
offering of the shares of common stock, the offering price and other selling
terms may from time to time be varied by the representatives.

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Duke Energy Field Services Corporation has granted to the U.S. underwriters
an option, exercisable for 30 calendar days from the date of this prospectus, to
purchase up to an aggregate of additional shares of common stock at
the public offering price listed on the cover page of this prospectus, less
underwriting discounts and commissions. The U.S. underwriters may exercise this
option solely for the purpose of covering over-allotments, if any, made in
connection with the offering of the shares of common stock offered by this
prospectus. To the extent the option is exercised, each U.S. underwriter will
become obligated, subject to certain conditions, to purchase about the same
percentage of the additional shares of common stock as the number listed next to
the U.S. underwriter's name in the preceding table bears to the total number of
shares of common stock listed next to the names of all U.S. underwriters in the
preceding table. If the U.S. underwriters' option is exercised in full, the
total price to the public would be $ , the total underwriters' discounts and
commissions would be $ and total proceeds to Duke Energy Field Services
Corporation would be $ .

The underwriters have informed Duke Energy Field Services Corporation that
they do not intend sales to discretionary accounts to exceed five percent of the
total number of shares of common stock offered by them.

We intend to file a listing application for our common stock with the NYSE
under the symbol "DEF."

Each of Duke Energy Field Services Corporation and our directors, executive
officers and certain of our stockholders has agreed that, without the prior
written consent of Morgan Stanley & Co. Incorporated on behalf of the
underwriters, it will not, during the period ending 180 days after the date of
this prospectus:

- offer, pledge, sell, contract to sell, sell any option or contract to
purchase, purchase any option or contract to sell, grant any option,
right or warrant to purchase, lend or otherwise transfer or dispose of
directly or indirectly, any shares of common stock or any securities
convertible into or exercisable or exchangeable for common stock; or

- enter into any swap or other arrangement that transfers to another, in
whole or in part, any of the economic consequences of ownership of the
common stock.

whether any transaction described above is to be settled by delivery of common
stock or such other securities, in cash or otherwise.

The restrictions described in this paragraph do not apply to:

- the sale of shares to the underwriters;

- the issuance by Duke Energy Field Services Corporation of shares of
common stock upon the exercise of an option or a warrant or the
conversion of a security outstanding on the date of this prospectus of
which the underwriters have been advised in writing; or

- transactions by any person other than Duke Energy Field Services
Corporation relating to shares of common stock or other securities
acquired in open market transactions after the completion of the offering
of the shares.

In order to facilitate the offering of the common stock, the underwriters
may engage in transactions that stabilize, maintain or otherwise affect the
price of the common stock. Specifically, the underwriters may over-allot in
connection with the offering, creating a short position in the common stock for
their own account. In addition, to cover over-allotments or to stabilize the
price of the common stock, the underwriters may bid for, and purchase, shares of
common stock in the open market. Finally, the underwriting syndicate may reclaim
selling concessions allowed to an underwriter or a dealer for distributing the
common stock in the offering, if the syndicate repurchases previously
distributed common stock in transactions to cover syndicate short positions, in
stabilization transactions or otherwise. Any of these activities may stabilize
or maintain the market price of the common stock above independent market
levels. The underwriters are not required to engage in these activities, and may
end any of these activities at any time.

From time to time, some of the underwriters have provided, and continue to
provide, investment banking services to Duke Energy Field Services Corporation,
Duke Energy, Phillips and their affiliates.
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Duke Energy Field Services Corporation and the underwriters have agreed to
indemnify each other against certain liabilities, including liabilities under
the Securities Act.

At the request of Duke Energy Field Services Corporation, the underwriters
have reserved for sale, at the initial offering price, up to shares
offered hereby for directors, officers, employees, business associates, and
related persons of Duke Energy Field Services Corporation. The shares of Common
Stock available for sale to the general public will be reduced to the extent
such persons purchase such reserved shares. Any reserved shares which are not so
purchased will be offered to the Underwriters to the general public on the same
basis as the other shares offered hereby.

PRICING OF THE OFFERINGS

Prior to the offerings, there has been no public market for the common
stock. The initial public offering price will be determined through negotiations
between Duke Energy Field Services Corporation and the U.S. representatives.
Among the factors to be considered in determining the initial public offering
price will be the future prospects of Duke Energy Field Services Corporation and
its industry in general, sales, earnings and certain other financial operating
information of Duke Energy Field Services Corporation in recent periods, and the
price-earnings ratios, price-sales ratios, market prices of securities and
certain financial and operating information of companies engaged in activities
similar to those of the company. The estimated initial public offering price
range set forth on the cover page of this preliminary prospectus is subject to
change as a result of market conditions and other factors.

VALIDITY OF THE COMMON STOCK

The validity of the shares of common stock we are offering 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.

EXPERTS

The combined financial statements of Duke Energy Field Services Corporation
and Affiliates and the 1997 combined statements of operations and cash flows for
UP Fuels Division included in this prospectus have been audited by Deloitte &
Touche LLP, independent auditors, as stated in their reports appearing herein,
and are included 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 appearing in this prospectus and elsewhere in the registration
statement have been audited by Ernst & Young LLP, independent auditors, as set
forth in their report thereon appearing elsewhere herein, and are included in
reliance upon such report given on the authority of such firm as experts in
accounting and auditing.

The consolidated financial statements of Union Pacific Fuels, Inc. as of
December 31, 1998 and March 31, 1999 included in this prospectus have been
audited by Arthur Andersen LLP, independent accountants, as stated in their
report on such financial statements which have been included herein in reliance
upon their authority as experts in auditing and accounting.

77
<PAGE> 80

ADDITIONAL INFORMATION

We have filed with the Securities and Exchange Commission a registration
statement on Form S-1 under the Securities Act, and the rules and regulations
promulgated thereunder, with respect to the common stock offered under this
prospectus. This prospectus, which constitutes a part of the registration
statement, does not contain all of the information set forth in the registration
statement and the attached exhibits and schedules. Statements contained in this
prospectus as to the contents of any contract or other document that is filed as
an exhibit to the registration statement are summaries of the material
provisions of those documents. These summaries are qualified in all respects by
reference to the full text of such contract or document.

The registration statement can be inspected and copied at the public
reference facilities maintained by the SEC at Room 1024, 450 Fifth Street, N.W.,
Washington, D.C. 20549, and at the SEC's regional offices at Seven World Trade
Center, 13th Floor, New York, New York 10048 and Northwestern Atrium Center, 500
West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of all or any
portion of the registration statement can be obtained from the Public Reference
Section of the SEC, 450 Fifth Street, N.W., Washington, D.C. 20549, at
prescribed rates. You may obtain information on the operation of the Public
Reference Section by calling the SEC at (800) 732-0330. In addition, the
registration statement is publicly available through the SEC's site on the
internet, located at http://www.sec.gov.

Upon completion of the offerings, we will be required to comply with the
informational requirements of the Securities and Exchange Act of 1934 and,
accordingly, will file current reports on Form 8-K, quarterly reports on Form
10-Q, annual reports on Form 10-K, proxy statements and other information with
the SEC. Those reports, proxy statements and other information will be available
for inspection and copying at the regional offices, public reference facilities
and internet site of the SEC referred to above. We intend to furnish our
stockholders with annual reports containing consolidated financial statements
certified by an independent public accounting firm.

78
<PAGE> 81

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
PRO FORMA ----
<S> <C>
DUKE ENERGY FIELD SERVICES CORPORATION (THE "COMPANY")
Unaudited Pro Forma Balance Sheet as of December 31,
1999................................................... 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-7
Notes to the Unaudited Pro Forma Income Statement......... F-8
HISTORICAL
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES (THE
"PREDECESSOR COMPANY")
Independent Auditors' Report.............................. F-11
Combined Balance Sheets at December 31, 1999 and 1998..... F-12
Combined Statements of Income for the Years Ended December
31, 1999, 1998 and 1997................................ F-13
Combined Statements of Stockholders' Equity for the Years
Ended December 31, 1999, 1998 and 1997................. F-14
Combined Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997....................... F-15
Notes to Combined Financial Statements.................... F-16
PHILLIPS GAS COMPANY ("GPM")
Report of Independent Auditors............................ F-29
Consolidated Balance Sheets at December 31, 1999 and
1998................................................... F-30
Consolidated Statements of Income for the Years Ended
December 31, 1999, 1998 and 1997....................... F-31
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997....................... F-32
Consolidated Statements of Changes in Stockholders' Equity
(Deficit) for the Years Ended December 31, 1999, 1998
and 1997............................................... F-33
Notes to Financial Statements............................. F-34
UP FUELS DIVISION OF UNION PACIFIC RESOURCES GROUP INC. ("UP
FUELS")
Reports of Independent Auditors........................... F-43
Combined Statements of Income for the Quarter Ended March
31, 1999 and the Years Ended December 31, 1998 and
1997................................................... F-45
Combined Statements of Cash Flows for the Quarter Ended
March 31, 1999 and the Years Ended December 31, 1998
and 1997............................................... F-46
Notes to Combined Financial Statements.................... F-47
</TABLE>

F-1
<PAGE> 82

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

The following unaudited pro forma financial statements (the "Unaudited Pro
Forma Financial Statements") of Duke Energy Field Services Corporation were
derived by the application of pro forma adjustments to historical combined and
consolidated financial statements included elsewhere in this prospectus. The
Unaudited Pro Forma Income Statement gives effect to i) the combination of the
North American Midstream natural gas businesses of Phillips Petroleum and Duke
Energy, the transfer of certain Midstream natural gas assets of Conoco, Inc.
("Conoco") and Mitchell Energy & Development Corp. ("Mitchell") acquired by the
Predecessor Company, prior to the consummation of the Combination, the transfer
of the general partner of TEPPCO Partners, L.P., a publicly traded master
limited partnership, and the Offerings (collectively, the "Transactions") and
ii) the acquisition of the gas gathering business of Union Pacific Resources
(the "UP Fuels Acquisition"), as if such transactions were consummated as of
January 1, 1999. The Unaudited Pro Forma Income Statement includes the results
of operations of UP Fuels for the three month period ending March 31, 1999, the
date the UP Fuels Acquisition was consummated. The Unaudited Pro Forma Balance
Sheet gives effect to the Transactions and the UP Fuels Acquisition as if such
transactions were consummated as of December 31, 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 Statement. 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, GPM and the notes thereto included elsewhere in
this prospectus.

F-2
<PAGE> 83

DUKE ENERGY FIELD SERVICES CORPORATION

UNAUDITED PRO FORMA BALANCE SHEET
AS OF DECEMBER 31, 1999
(IN THOUSANDS)

<TABLE>
<CAPTION>
PREDECESSOR
COMPANY GPM
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
CURRENT ASSETS
Cash and cash equivalents................................. $ 792 $ 164,078 $ (102,612)(1) $ 62,258
Accounts receivable:
Customers, net.......................................... 370,139 104,555 474,694
Affiliates.............................................. 63,927 104,159 168,086
Other................................................... 30,067 30,067
Inventories............................................... 38,701 3,066 41,767
Notes receivable.......................................... 13,050 10,000(2) 23,050
Deferred income taxes..................................... 30,293 (27,025)(3) 3,268
Other..................................................... 1,580 3,407 4,987
---------- ---------- ---------- ----------
518,256 409,558 (119,637) 808,177

PROPERTY AND EQUIPMENT, NET................................. 2,409,385 995,406 1,204,899(4) 4,609,690

INVESTMENT IN AFFILIATES.................................... 347,735 3,421 (40,195)(5) 310,961

INTANGIBLE ASSETS
Natural Gas liquids sales contracts, net.................. 102,382 102,382
Goodwill, net............................................. 81,946 289,415(4) 371,361

OTHER NONCURRENT ASSETS..................................... 12,131 56,826 3,615(6) 72,572
---------- ---------- ---------- ----------
TOTAL ASSETS................................................ $3,471,835 $1,465,211 $1,338,097 $6,275,143
========== ========== ========== ==========
CURRENT LIABILITIES
Accounts payable
Trade................................................... 353,977 178,891 532,868
Affiliates.............................................. 62,370 106,410 168,780
Other................................................... 33,858 33,858
Accrued taxes other than income........................... 15,653 11,606 27,259
Advances from parent, net................................. 1,579,475 534 (1,580,009)(7)
Notes payable -- affiliates............................... 588,880 (588,880)(7)
Indebtedness.............................................. 1,983,000(8) 1,983,000
Other..................................................... 6,372 8,363 14,735
---------- ---------- ---------- ----------
2,640,585 305,804 (185,889) 2,760,500

DEFERRED INCOME TAXES....................................... 308,308 128,907 393,760(9) 830,975

NOTE PAYABLE TO PARENT...................................... 101,600 1,350,000 (1,451,600)(7)

OTHER LONG TERM LIABILITIES................................. 34,871 18,219 53,090

STOCKHOLDERS' EQUITY (DEFICIT).............................. 386,471 (337,719) 2,581,826(10) 2,630,578
---------- ---------- ---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $3,471,835 $1,465,211 $1,338,097 $6,275,143
========== ========== ========== ==========
</TABLE>

See accompanying Notes to the Unaudited Pro Forma Balance Sheet.
F-3
<PAGE> 84

DUKE ENERGY FIELD SERVICES CORPORATION

NOTES TO THE UNAUDITED PRO FORMA BALANCE SHEET
AS OF DECEMBER 31, 1999
(IN THOUSANDS)

In December 1999, Duke Energy Field Services Corporation (the "Company")
and its subsidiary Duke Energy Field Services LLC ("Field Services LLC") were
formed to facilitate the combination of the midstream natural gas businesses of
Duke Energy and Phillips Petroleum Company (the "Combination"). The Company was
capitalized with 1,000 shares of common stock with a par value of $1 per share.

In connection with the Combination, the midstream natural gas businesses of
Duke Energy and Phillips were contributed to Field Services LLC. In addition to
the Predecessor Company, Duke Energy contributed to Field Services LLC the
General Partner of the TEPPCO Partners, L.P. a publicly traded master limited
partnership ("TEPPCO General Partner") and the mid-continent midstream natural
gas assets of Conoco, Inc. and Mitchell Energy & Development Corp. acquired
prior to the Combination. On March 31, 2000 Field Services LLC borrowed
$2,743,000 in commercial paper (the "Indebtedness"), and made distributions of
$1,522,750 to Duke Energy and $1,220,000 to Phillips. In connection with the
Offerings, the Company acquired the Phillips member interests in Field Services
LLC in exchange for shares of the Company.

In connection with the Combination, the Company sold its investment in
Westana for cash of $11,901 and incurred a loss of $2,271, net of a tax benefit
of $1,392.

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 historical balances to give effect to the 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>
<S> <C>
Sources of Funds:
Indebtedness........................................... $2,743,000
Proceeds from the Offerings............................ 800,000
Net cash settlement for working capital................ 59,315
Proceeds from sale of Westana Investment............... 11,901
----------
Total Sources..................................... $3,614,216
----------
Uses of Funds:
Distribution to Duke Energy and Phillips............... $2,742,750
Pay-down of the Indebtedness........................... 760,000
Payment of estimated transaction fees.................. 50,000
Settlement of advances from Phillips................... 164,078
----------
Total Uses........................................ $3,716,828
==========
Net adjustment to cash................................. $ (102,612)
==========
</TABLE>

2. Reflects notes receivable recorded in connection with the transfer of the
TEPPCO General Partnership interest.

F-4
<PAGE> 85
DUKE ENERGY FIELD SERVICES CORPORATION

NOTES TO THE UNAUDITED PRO FORMA BALANCE SHEET (CONTINUED)

AS OF DECEMBER 31, 1999
(IN THOUSANDS)

3. Reflects the following:

<TABLE>
<S> <C>
Net operating loss carry-forward credits and AMT
credits that will not be available to the Company as a
result of the Combination............................. $ (27,551)
Tax benefit related to write-off of deferred fees in
the Offerings......................................... 526
-----------
Net adjustment......................................... $ (27,025)
===========
</TABLE>

4. The pro forma adjustment to property and equipment, and goodwill represents
the step-up to fair value of the net assets acquired as follows:

<TABLE>
<S> <C>
Purchase price (estimated value)....................... $ 1,900,000
Non-financing portion of Combination estimated fees.... 5,000
Deferred tax impact of basis difference in the
Combination........................................... 289,415
-----------
Total purchase price.............................. 2,194,415
Less net assets acquired, including the effect of
assets and liabilities to be retained by Phillips..... (845,382)
-----------
Excess of purchase price over net assets acquired...... $ 1,349,033
===========
</TABLE>

The excess purchase cost over the book value of net assets acquired has not
yet been fully allocated to individual assets and liabilities acquired. The
final allocation of the excess of the purchase price over the book value of
the GPM assets acquired will be determined based on independent appraisals.
Management's preliminary allocation of such excess is as follows:

<TABLE>
<S> <C>
Property and Equipment, net............................ $ 1,059,618
Goodwill............................................... 289,415
-----------
$ 1,349,033
===========
</TABLE>

The net adjustment to property also reflects the additional acquisitions by
the Company since the execution of the Combination agreement as follows:

<TABLE>
<S> <C>
Step up from above..................................... $ 1,059,618
Acquisitions since combination agreement............... 145,281
-----------
Net adjustment......................................... $ 1,204,899
===========
</TABLE>

5. Reflects the following:

<TABLE>
<S> <C>
Sale of Westana........................................ $ (15,564)
Transfer of TEPPCO General Partner from Duke........... 2,900
Exchange of Ferguson-Burleson investment for Mitchell
property and equipment................................ (27,531)
-----------
Net adjustment......................................... $ (40,195)
===========
</TABLE>

F-5
<PAGE> 86
DUKE ENERGY FIELD SERVICES CORPORATION

NOTES TO THE UNAUDITED PRO FORMA BALANCE SHEET (CONTINUED)

AS OF DECEMBER 31, 1999
(IN THOUSANDS)

6. Reflects the payment and deferral of financing fees associated with the
Combination and the write-off of a portion of the fees when the Indebtedness
is paid down with the proceeds of the Offerings as follows:

<TABLE>
<S> <C>
Deferred financing fees associated with the
Indebtedness.......................................... $ 5,000
Deferred fees written-off with portion of the
Indebtedness.......................................... (1,385)
-----------
Net adjustment......................................... $ 3,615
===========
</TABLE>

7. Reflects the discharge of intercompany notes and advances of the Company
owed to Duke and the intercompany and advances to GPM from Phillips.

8. Reflects the Indebtedness incurred in connection with the Combination. On
March 31, 2000, Field Services LLC entered into a $2,800,000 credit facility
with several financial institutions (the "Credit Facility"). The Credit
Facility will be used as the liquidity backstop to support the Field
Services LLC commercial paper program. On March 31, 2000 Field Services LLC
borrowed $2,743,000 in the commercial paper market to fund the Combination
and for the settlement of certain advances from Duke Energy and Phillips
related to acquisitions completed prior to the Combination. The commercial
paper has maturities ranging from days to days and had annual interest
rates between % and %. The Credit Facility, which is not expected
to be drawn upon, matures on March 30, 2001, bears interest at a rate equal
to, at the Company's option, either (1) LIBOR plus 0.50% per year for the
first 90 days following the closing of the credit facility and 0.625% per
year thereafter or (2) the higher of (a) the Bank of America prime rate and
(b) the Federal Funds rate plus 0.50% per year. Upon completion of the
Offerings, Field Services LLC obligations under the facility were assumed by
the Company and became an unsecured obligation.

The Company plans to refinance a portion of the commercial paper with the
proceeds of a term credit facility. Accordingly, pro forma interest expense
has been calculated using Management's estimate of the weighted average rate
at which the Company believes it will be able to refinance the commercial
paper. Management believes that 8% is the appropriate interest rate for such
an estimate. Such rate is higher than the prevailing commercial paper
interest rate available as of the date of this filing.

The net adjustment to Indebtedness results from the following:

<TABLE>
<CAPTION>
<S> <C>
Indebtedness........................................... $ 2,743,000
Pay-down of the Indebtedness with the net proceeds of
the Offerings......................................... (760,000)
-----------
Net adjustment......................................... $ 1,983,000
===========
</TABLE>

9. Reflects the following:

<TABLE>
<CAPTION>
<S> <C>
Deferred tax effect of the step-up of GPM assets in the
Combination........................................... $ 289,415
Adjustment to deferred taxes to reflect loss of NOL and
AMT credits not available to the Company as a result
of the Combination.................................... 63,145
Deferred taxes from the transfer of TEPPCO General
Partner interest from Duke Energy..................... 41,200
-----------
Net adjustment......................................... $ 393,760
===========
</TABLE>

F-6
<PAGE> 87
DUKE ENERGY FIELD SERVICES CORPORATION

NOTES TO THE UNAUDITED PRO FORMA BALANCE SHEET (CONTINUED)

AS OF DECEMBER 31, 1999
(IN THOUSANDS)

10. The pro forma adjustment to total stockholders' equity related to the
Transactions reflects the following:

<TABLE>
<S> <C>
Discharge of Duke intercompany notes and advances...... $ 2,269,955
Discharge of Phillips intercompany advances............ 1,186,456
Issuance of Field Services LLC member interests for
stock of GPM.......................................... 1,900,000
Estimated net proceeds of the Offerings................ 760,000
Net working capital settlements........................ 59,315
Effect of distribution to Duke and Phillips............ (2,625,000)
Elimination of adjusted equity of GPM.................. (845,382)
Transfer of TEPPCO General Partner from Duke Energy.... (28,300)
Write-off of NOLs and AMT credits in Combination....... (90,696)
Loss on sale of Westana, including tax benefit
converted to equity................................... (3,663)
Write-off of deferred financing fees related to the
pay-down of indebtedness with the proceeds of the
Offerings, net of tax................................. (859)
-----------
Net adjustment......................................... $ 2,581,826
===========
</TABLE>

F-7
<PAGE> 88

DUKE ENERGY FIELD SERVICES CORPORATION

UNAUDITED PRO FORMA INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PREDECESSOR
COMPANY UP FUELS GPM
HISTORICAL ACQUISITION(1) SUBTOTAL HISTORICAL ADJUSTMENTS(2) PRO FORMA
----------- -------------- ---------- ---------- -------------- ----------
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES
Sales of natural gas and petroleum
products.............................. $3,310,260 $228,600 $3,538,860 $1,501,178 $ 228,889(3) $5,268,927
Transportation, storage and
processing............................ 148,050 69,324 217,374 88,279 305,653
---------- -------- ---------- ---------- --------- ----------
Total operating revenues.......... 3,458,310 297,924 3,756,234 1,589,457 228,889 5,574,580

COSTS AND EXPENSES
Natural gas and petroleum products...... 2,965,297 252,880 3,218,177 1,148,910 187,689(3) 4,554,776
Operating and maintenance............... 181,392 22,478 203,870 176,864 12,400(3) 393,134
Depreciation and amortization........... 130,788 15,125 145,913 80,458 46,246(4) 272,617
General and administrative.............. 73,685 6,465 80,150 15,560 95,710
Net (gain) loss on sale of assets....... 2,377 2,377 (907) 1,470
---------- -------- ---------- ---------- --------- ----------
Total costs and expenses.......... 3,353,539 296,948 3,650,487 1,420,885 246,335 5,317,707
---------- -------- ---------- ---------- --------- ----------

OPERATING INCOME (LOSS).................. 104,771 976 105,747 168,572 (17,446) 256,873

EQUITY IN EARNINGS OF UNCONSOLIDATED
AFFILIATES.............................. 22,502 4,821 27,323 1,048 (1,033) (5) 27,338
---------- -------- ---------- ---------- --------- ----------
EARNINGS (LOSS) BEFORE INTEREST AND
TAXES................................... 127,273 5,797 133,070 169,620 (18,479) 284,211
INTEREST EXPENSE......................... 52,915 52,915 35,643 70,534(6) 159,092
---------- -------- ---------- ---------- --------- ----------
EARNINGS (LOSS) BEFORE INCOME TAXES...... 74,358 5,797 80,155 133,977 (89,013) 125,119
INCOME TAXES............................. 31,029 2,000 33,029 52,244 (28,327)(7) 56,946
---------- -------- ---------- ---------- --------- ----------
INCOME (LOSS) FROM CONTINUING
OPERATIONS.............................. $ 43,329 $ 3,797 $ 47,126 $ 81,733 $ (60,686) $ 68,173
========== ======== ========== ========== ========= ==========
BASIC EARNINGS PER COMMON SHARE..........
==========
DILUTED EARNINGS PER COMMON SHARE........
==========
WEIGHTED AVERAGE BASIC SHARES
OUTSTANDING.............................
==========
WEIGHTED AVERAGE DILUTED SHARES
OUTSTANDING.............................
==========
</TABLE>

See accompanying Notes to the Unaudited Pro Forma Income Statement
F-8
<PAGE> 89

DUKE ENERGY FIELD SERVICES CORPORATION

NOTES TO THE UNAUDITED PRO FORMA INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31, 1999
(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 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 ending March 31, 1999 the date the UP Fuels Acquisition was
consummated by the Predecessor Company.

2. 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. Such expenses
relate principally to the write-off of existing deferred financing fees on
debt repaid as described in Note (6) to the Unaudited Pro Forma Balance
Sheet.

3. Reflects the results of operations associated with the acquisition of the
Conoco and Mitchell businesses.

4. 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 and
the remainder, representing goodwill, 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>
<S> <C>
Net book value of GPM property and equipment at January 1,
1999...................................................... $ 943,302
Excess purchase price over net assets acquired in
Combination
allocated to property and equipment....................... 1,177,368
allocated to goodwill..................................... 289,415
---------
Subtotal.................................................. 2,410,085
Composite life............................................ 20
---------
Depreciation and amortization calculated.................... 120,504
Conoco and Mitchell businesses depreciation................. 6,200
Less: GPM historical depreciation and amortization.......... (80,458)
---------
Net adjustment.............................................. $ 46,246
=========
</TABLE>

5. Reflects elimination of the equity earnings associated with the Predecessor
Company's investment in Westana and Ferguson/Burleson and the addition of
equity income from the TEPPCO General Partnership interest transferred from
Duke Energy.

<TABLE>
<S> <C>
Equity income from Westana.................................. $(1,339)
Equity income from the Ferguson/Burleson businesses......... (8,994)
Equity income from the TEPPCO General Partnership
interests................................................. 9,300
-------
Net adjustment.............................................. $(1,033)
=======
</TABLE>

F-9
<PAGE> 90
DUKE ENERGY FIELD SERVICES CORPORATION

NOTES TO THE UNAUDITED PRO FORMA INCOME STATEMENT (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS)

6. The pro forma adjustment to interest expense, net under the new capital
structure is as follows:

<TABLE>
<CAPTION>
INTEREST
EXPENSE
---------
<S> <C>
Indebtedness at estimated weighted average interest rate of
8%........................................................ $ 219,410
Amortization of deferred financing costs over estimated
weighted average life of 7.5 years........................ 667
---------
subtotal.................................................. 220,077
---------
Less: historical interest expense........................... (88,558)
---------
Incremental interest expense from the Indebtedness before
the Offerings............................................. 131,519
---------

Indebtedness paid down with the net proceeds of the
Offerings................................................. (760,000)
Estimated weighted average interest rate.................... 8.0%
subtotal.................................................. (60,800)
Deferred fees written off in pay-down of the Indebtedness... (1,385)
Estimated weighted average life............................. 7.5
---------
Reduction in amortization................................... (185)
---------
Reduction of interest expense resulting from pay-down of the
Indebtedness.............................................. (60,985)
---------
Net adjustment.............................................. $ 70,534
=========
</TABLE>

A .125% increase or decrease in the assumed weighted average interest rate
would change pro forma interest expense with respect to the Indebtedness by
$2,479 after pay-down with the proceeds of the Offerings. Pro forma net income
would change by $1,537.

7. The pro forma adjustment to income taxes reflects the use of the combined
federal and state statutory income tax rate of 38% on pro forma taxable
income, which is adjusted for the increase in non-deductible goodwill
amortization as follows:

<TABLE>
<CAPTION>
PRO FORMA
ADJUSTMENT AMOUNT RATE ADJUSTMENT
---------- -------- ---- ----------
<S> <C> <C> <C>
Incremental deductible depreciation on stepped-up GPM
assets.................................................... $(25,576) 38.0% $ (9,719)
Net adjustment to equity in earnings of unconsolidated
affiliates................................................ (1,033) 38.0% (393)
Incremental interest expense under the Indebtedness......... (70,534) 38.0% (26,803)
Earnings before taxes of the Conoco/Mitchell businesses..... 22,600 38.0% 8,588
-------- --------
Net adjustment.............................................. $(74,543) $(28,327)
======== ========
</TABLE>

F-10
<PAGE> 91

INDEPENDENT AUDITORS' REPORT

Duke Energy Field Services Corporation and Affiliates

We have audited the accompanying combined balance sheets of Duke Energy
Field Services Corporation and Affiliates ("the Predecessor Companies") as of
December 31, 1999 and 1998, and the related combined statements of income and
stockholders' 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, 1999 and 1998, 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-11
<PAGE> 92

DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

<TABLE>
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 792 $ 168
Accounts receivable:
Customers (net of allowance for doubtful accounts,
1999, $6,743 and 1998, $749).......................... 370,139 155,143
Affiliates............................................. 63,927 57,725
Other.................................................. 30,067 27,246
Inventories............................................... 38,701 23,713
Notes receivable.......................................... 13,050 5,266
Other..................................................... 1,580 531
---------- ----------
Total current assets.............................. 518,256 269,792
PROPERTY, PLANT AND EQUIPMENT:
Cost...................................................... 3,005,510 1,763,594
Accumulated depreciation and amortization................. (596,125) (480,296)
---------- ----------
Net property, plant, and equipment................ 2,409,385 1,283,298
INVESTMENTS IN AFFILIATES................................... 347,735 187,938
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net.................. 102,382
Goodwill, net............................................. 81,946 15,299
OTHER NONCURRENT ASSETS..................................... 12,131 14,511
---------- ----------
TOTAL ASSETS................................................ $3,471,835 $1,770,838
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade.................................................. $ 353,977 $ 200,864
Affiliates............................................. 62,370 10,762
Other.................................................. 33,858 5,556
Accrued taxes other than income........................... 15,653 14,194
Advances, net -- parents.................................. 1,579,475 334,057
Notes payable -- affiliates............................... 588,880 540,000
Other..................................................... 6,372 8,976
---------- ----------
Total current liabilities......................... 2,640,585 1,114,409
DEFERRED INCOME TAXES....................................... 308,308 222,007
NOTE PAYABLE TO PARENT...................................... 101,600 101,600
OTHER LONG TERM LIABILITIES................................. 34,871
COMMITMENTS AND CONTINGENT LIABILITIES
STOCKHOLDERS' EQUITY:
Common stock.............................................. 1 3
Paid-in capital........................................... 213,091 202,523
Retained earnings......................................... 173,091 130,296
Other comprehensive income................................ 288
---------- ----------
Total stockholders' equity........................ 386,471 332,822
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $3,471,835 $1,770,838
========== ==========
</TABLE>

See notes to combined financial statements.

F-12
<PAGE> 93

DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

See notes to combined financial statements.

F-13
<PAGE> 94

DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(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 combined financial statements.

F-14
<PAGE> 95

DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

See notes to combined financial statements.

F-15
<PAGE> 96

DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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 Corporation ("the Company"), 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
Corporation and Affiliates" or the "Predecessor Companies"). The Predecessor
Companies are indirect wholly-owned 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 the Company and DESCL.

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 ("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 at December 31,
1999 or 1998. Depreciation of property, plant and equipment is computed using
the straight-line method (see Note 4).

Interest totaling $.9 million, $1.6 million and $2.3 million has been
capitalized on construction projects for 1999, 1998 and 1997, 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. A reserve of $6 million was established in
connection with the UP Fuels acquisition (see Note 2).

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 have the ability to
exercise control.

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 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.

F-16
<PAGE> 97
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

Intangibles Amortization -- Goodwill is 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.

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.

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 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

F-17
<PAGE> 98
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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... 120,544
Natural gas liquids sales contracts................ 107,771
Goodwill........................................... 71,648
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 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. 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.

3. INVENTORIES

A summary of inventories by category follows:

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

4. PROPERTY, PLANT AND EQUIPMENT

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

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

F-18
<PAGE> 99
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

5. INVESTMENTS IN AFFILIATES

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

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
OWNERSHIP 1999 1998
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Dauphin Island Gathering Partners................... 37.28% $ 99,878 $ 96,869
Mont Belvieu I...................................... 20.00% 40,440
Mobile Bay Processing Partners...................... 28.50% 35,906 30,166
Black Lake Pipeline................................. 50.00% 35,641
Sycamore Gas System General Partnership............. 48.45% 21,985 19,344
Main Pass Oil Gathering............................. 33.33% 16,967 15,762
Ferguson-Burleson................................... 55.00% 27,531
Other affiliates.................................... Various 54,141 12,406
-------- --------
332,489 174,547
Westana Gathering Company........................... 50.00% 15,246 13,391
-------- --------
Total investments in affiliates........... $347,735 $187,938
======== ========
</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.

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 do not operate or control
Ferguson-Burleson.

F-19
<PAGE> 100
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

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

Distributions in excess of earnings were $9.5 million, $3.2 million and
$958 thousand in 1999, 1998 and 1997, respectively.

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

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

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

F-20
<PAGE> 101
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

6. TRANSACTIONS WITH AFFILIATES

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

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

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

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

As of December 31, 1999 and 1998, 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 have 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.

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.

F-21
<PAGE> 102
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
-------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Current:
Federal........................................... $(46,429) $(36,142) $(1,012)
State............................................. (8,843) (5,884) (1,431)
-------- -------- -------
Total current............................. (55,272) (42,026) (2,443)
-------- -------- -------
Deferred:
Federal........................................... 73,201 38,961 30,800
State............................................. 13,100 6,354 5,023
-------- -------- -------
Total deferred............................ 86,301 45,315 35,823
-------- -------- -------
Total income tax expense............................ $ 31,029 $ 3,289 $33,380
======== ======== =======
</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,
----------------------------
1999 1998 1997
------- ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal income tax rate................................ 35.0% 35.0% 35.0%
======= ====== =======
Income tax, computed at the statutory rate............. $26,025 $1,861 $29,616
Adjustments resulting from:
State income tax, net of federal income tax effect... 2,863 186 2,962
Non-deductible amortization and other................ 2,141 1,242 802
------- ------ -------
Total income tax............................. $31,029 $3,289 $33,380
======= ====== =======
</TABLE>

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

F-22
<PAGE> 103
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

8. BUSINESS SEGMENTS AND RELATED INFORMATION

The Predecessor Companies operate in two principal business segments as
follows: natural gas gathering, processing, transportation, marketing and
storage, and 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, operating income and earnings
before interest, taxes, depreciation and amortization are the performance
measures utilized by management to monitor the business of each segment.

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

<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues:
Natural gas............................................ $2,483,197 $1,497,901 $1,683,483
NGLs................................................... 1,365,577 309,380 423,680
Intersegment........................................... (390,464) (222,961) (305,331)
---------- ---------- ----------
Total operating revenues....................... 3,458,310 1,584,320 1,801,832
---------- ---------- ----------
Margin:
Natural gas............................................ 459,843 243,787 334,129
NGLs................................................... 33,170 2,404 (386)
---------- ---------- ----------
Total margin................................... 493,013 246,191 333,743
---------- ---------- ----------
Operating Income:
Natural gas............................................ 158,356 90,520 164,464
NGLs................................................... 22,390 2,404 (386)
Corporate.............................................. (75,975) (47,049) (38,131)
---------- ---------- ----------
Total operating income......................... 104,771 45,875 125,947
---------- ---------- ----------
EBITDA:
Natural gas............................................ 305,919 176,436 239,841
NGLs................................................... 33,048 2,404 (386)
Corporate.............................................. (80,906) (45,547) (36,023)
---------- ---------- ----------
Total EBITDA........................................... 258,061 133,293 203,432
---------- ---------- ----------
Total assets:
Natural gas............................................ 2,859,667 1,609,835
NGLs................................................... 225,702 5,137
Corporate(a)........................................... 386,466 155,866
---------- ----------
Total assets................................... $3,471,835 $1,770,838
========== ==========
</TABLE>

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

(a) Includes items such as unallocated working capital, intercompany accounts
and intangible and other assets.

F-23
<PAGE> 104
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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 natural gas liquids prices) and
natural gas liquids 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 natural gas liquids 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 is approximately 2 months at December 31, 1999. During
1999 net gains of $9.7 million were recognized from trading natural gas liquids
and crude oil derivatives. The Predecessor Companies were not trading natural
gas liquids nor crude oil commodity instruments prior to 1999. As of December
31, 1999, the absolute notional contract quantity of natural gas liquids 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, 1999 and 1998, 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 natural gas liquids. 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 natural gas liquids.

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, 1999 and 1998, the Predecessor Companies unrealized net
gains (losses) related to commodity derivative hedges was $(63.5) million and
$1.8 million, respectively. As of December 31, 1999 and 1998, the absolute
notional contract quantity of commodity derivatives held for non-trading
purposes was 7.8 and 10.92 billion cubic feet (Bcf) of natural gas and
32,764,000 and 59,000 barrels of crude oil, respectively. Hedging losses in 1999
totalled approximately $34 million.

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

F-24
<PAGE> 105
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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, 1999 DECEMBER 31, 1998
--------------------------- -------------------------
CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR
AMOUNT VALUE AMOUNT VALUE
---------- -------------- -------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents.............. $ 792 $ 792 $ 168 $ 168
Accounts receivable.................... 464,133 464,133 240,114 240,114
Notes receivable....................... 21,866 22,582 15,096 15,294
Accounts payable....................... 450,205 450,205 217,182 217,182
Advances, net -- parents............... 1,579,475 1,579,475 334,591 334,591
Notes payable.......................... 690,480 655,843 641,600 601,606
Natural gas, NGL and oil hedge
contracts............................ -- (63,500) -- 1,800
</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.

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.

F-25
<PAGE> 106
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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.

The Predecessor Companies utilize assets under operating leases in several
areas of operation. Combined rental expense amounted to $11.8 million, $8.2
million and $8.1 million in 1999, 1998 and 1997, 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.

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. Key
employees of the Predecessor Companies were granted stock options of 827,724,
279,500 and 0 in 1999, 1998 and 1997, respectively. Outstanding stock options at
December 31, 1999, 1998 and 1997 were 1,105,380, 328,201 and 118,586,
respectively. There were 276,806, 82,050 and 29,646 options exercisable at
December 31, 1999, 1998 and 1997, with a weighted average exercise price of $34,
$22 and $21 per option, 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 in 1999 and 1998 were: stock dividend yield of 4.1% and 4.2%,
expected stock price volatility of 18.8% and 15.1% and risk-free interest rates
of 5.9% and 5.6%, respectively. The expected option life for 1999 and 1998 was 7
years. Stock-based compensation expense calculated using the Black-Scholes
option-pricing model for 1999 and 1998 would have been $2.5 million and $0.8
million, respectively. Had compensation expense for stock-based compensation
been determined based on the fair value at the grant dates, 1999 and 1998 net
income would have been $45.3 million and $8.1 million, respectively; and 1997
net income would have been unchanged.

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 1999 and 1997 Duke Energy awarded 36,300 shares (fair value at
grant dates of approximately $2 million) and 2,817 shares (fair value at grant
dates of approximately $168 thousand) 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 $488 thousand, $0 and $168
thousand in 1999, 1998 and 1997, 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
F-26
<PAGE> 107
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

RECONCILIATION OF FUNDED STATUS TO PRE-FUNDED PENSION COSTS

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

F-27
<PAGE> 108
DUKE ENERGY FIELD SERVICES CORPORATION AND AFFILIATES

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

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

ASSUMPTIONS USED FOR PENSION BENEFIT ACCOUNTING

<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
--------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Discount rate............................................... 7.50% 6.75% 7.25%
Rate of increase in compensation levels..................... 4.50% 4.67% 4.75%
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 1999, 1998 and 1997, the Predecessor
Companies expensed plan contributions of $3.6 million, $1.8 million and $1.6
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
1999, 1998 and 1997.

F-28
<PAGE> 109

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, 1999 and 1998, 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, 1999 and 1998, 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-29
<PAGE> 110

PHILLIPS GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

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

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

LIABILITIES

Accounts payable
Affiliate................................................. $ 106,410 $ 23,946
Trade..................................................... 178,891 139,729
Deferred purchase obligation due within one year............ 8,300 --
Accrued income and other taxes.............................. 12,140 8,363
Other accruals.............................................. 63 212
---------- ----------
Total Current Liabilities......................... 305,804 172,250
Long-term debt due to affiliate............................. 1,350,000 560,000
Other liabilities and deferred credits...................... 3,065 4,908
Deferred income taxes....................................... 128,907 68,160
Deferred gain on sale of assets............................. 15,154 16,237
---------- ----------
Total Liabilities................................. 1,802,930 821,555
---------- ----------
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)..................... (337,719) 217,631
---------- ----------
Total Stockholder's Equity/(Deficit).............. (337,719) 360,548
---------- ----------
Total............................................. $1,465,211 $1,182,103
========== ==========
</TABLE>

See Notes to Financial Statements.

F-30
<PAGE> 111

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)

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

See Notes to Financial Statements.

F-31
<PAGE> 112

PHILLIPS GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

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

See Notes to Financial Statements.

F-32
<PAGE> 113

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-33
<PAGE> 114

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 1999 and 1998, 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
straight-line method over an estimated life of 20 years for most of the assets.
Other properties and equipment are depreciated using the straight-line method
over the estimated useful lives of the 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 production volumes, prices and costs used for
planning purposes by the company. These may differ from levels prevalent at the
impairment review date due to anticipated changes in outlook for production
levels, supply and demand influences in the marketplace, and general inflation.

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.

F-34
<PAGE> 115
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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.

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 1999 and 1998 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. 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 represent operating segments, which have been aggregated 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.

3. INVENTORIES

Inventories at December 31 consisted of the following:

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

The company's helium inventory was sold in March 1999 for $4,989,000.

F-35
<PAGE> 116
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

4. INVESTMENTS AND LONG-TERM RECEIVABLES

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

<TABLE>
<CAPTION>
1999 1998
------ -------
(IN THOUSANDS)
<S> <C> <C>
Investment in affiliated company............................ $3,421 $ 3,328
Long-term receivables....................................... 6,164 9,685
------ -------
$9,585 $13,013
====== =======
</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. 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 long-term
contract. 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 1999
and 1998 was $1,083,000 and $1,082,000, respectively. Distributions received
from GGG during 1999 and 1998 were $955,000 and $1,153,000 respectively.

5. PROPERTIES, PLANTS AND EQUIPMENT

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

<TABLE>
<CAPTION>
1999 1998
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Properties, plants and equipment (at cost).................. $2,267,004 $2,143,560
Less accumulated depreciation and amortization.............. 1,271,598 1,200,258
---------- ----------
$ 995,406 $ 943,302
========== ==========
</TABLE>

6. DEBT

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

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

F-36
<PAGE> 117
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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.

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.

F-37
<PAGE> 118
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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

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

(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.

(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. Selling,
general and

F-38
<PAGE> 119
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

administrative expenses included a $2 million severance charge in 1999, and
a severance charge reversal of $2 million in 1998.

(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 1999, 1998 and 1997, the total gathering fees were
$41,447,000, $42,951,000 and $42,755,000, respectively, of which
$34,316,000, $35,720,000 and $34,952,000, 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 $72,000, $79,000 and $120,000 in
1999, 1998 and 1997, 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 $239,000, $60,000 and $22,000 in 1999, 1998 and 1997,
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 1999, 1998 and 1997 were
$2,175,000, $2,276,000 and $3,942,000, 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.

12. INCOME TAXES

Taxes charged to income were:

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

F-39
<PAGE> 120
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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

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

F-40
<PAGE> 121
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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.

14. CASH FLOW INFORMATION

<TABLE>
<CAPTION>
1999 1998 1997
-------- ------- -------
(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............................................... 32,789 36,108 20,452
Income taxes, including payments to Phillips........... 20,773 123 25,432
</TABLE>

15. OTHER FINANCIAL INFORMATION

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

F-41
<PAGE> 122
PHILLIPS GAS COMPANY

NOTES TO FINANCIAL STATEMENTS--CONTINUED

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-42
<PAGE> 123

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 three-month period ended March 31, 1999 and year ended
December 31, 1998. 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 three-month period ended March 31, 1999
and year ended December 31, 1998, in conformity with accounting principles
generally accepted in the United States.

ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 10, 2000

F-43
<PAGE> 124

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. 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-44
<PAGE> 125

UPFUELS DIVISION

COMBINED STATEMENTS OF INCOME

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

<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998 1997
--------- -------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues:
Gathering and processing.................................. $ 54.5 $ 227.2 $ 321.7
Pipelines................................................. 75.8 305.0 401.2
Marketing................................................. 784.0 3,062.8 2,761.6
Intersegment.............................................. (45.2) (188.6) (269.3)
------ -------- --------
Total operating revenues............................ 869.1 3,406.4 3,215.2
------ -------- --------
Product purchases:
Gathering and processing.................................. 30.9 119.6 157.1
Pipelines................................................. 44.9 198.4 312.4
Marketing................................................. 757.9 2,986.3 2,728.5
Intersegment.............................................. (45.2) (188.6) (269.3)
------ -------- --------
Total product purchases............................. 788.5 3,115.7 2,928.7
------ -------- --------
Gross margin:
Gathering and processing.................................. 23.6 107.6 164.6
Pipelines................................................. 30.9 106.6 88.8
Marketing................................................. 26.1 76.5 33.1
------ -------- --------
Total gross margin.................................. 80.6 290.7 286.5
------ -------- --------
Operating expenses:
Gathering and processing.................................. 17.7 66.4 57.9
Pipelines................................................. 7.8 37.3 27.3
Marketing................................................. -- -- --
------ -------- --------
Total operating expenses............................ 25.5 103.7 85.2
------ -------- --------
General & administrative expenses:
Gathering and processing.................................. 1.9 8.0 6.0
Pipelines................................................. 0.7 2.9 1.3
Marketing................................................. 3.0 13.0 13.0
Corporate................................................. 1.5 5.2 5.0
------ -------- --------
Total general & administrative expenses............. 7.1 29.1 25.3
------ -------- --------
Depreciation and amortization expense
Gathering and processing.................................. 11.8 41.6 44.0
Pipelines................................................. 8.0 32.7 29.4
Marketing................................................. 4.1 6.2 1.1
------ -------- --------
Total depreciation and amortization expense......... 23.9 80.5 74.5
------ -------- --------
Operating income (loss):
Gathering and processing.................................. (7.8) (8.4) 56.7
Pipelines................................................. 14.4 33.7 30.8
Marketing................................................. 19.0 57.3 19.0
Corporate................................................. (1.5) (5.2) (5.0)
------ -------- --------
Total operating income.............................. 24.1 77.4 101.5
------ -------- --------
Other income................................................ -- 0.6 --
Minority interest........................................... (2.1) (7.6) (9.8)
------ -------- --------
Income before income taxes.................................. 22.0 70.4 91.7
Income taxes................................................ 8.1 26.1 33.9
------ -------- --------
Net income.................................................. $ 13.9 $ 44.3 $ 57.8
------ -------- --------
</TABLE>

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

F-45
<PAGE> 126

UPFUELS DIVISION

COMBINED STATEMENTS OF CASH FLOWS

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

<TABLE>
<CAPTION>
DECEMBER 31,
MARCH 31, 1999 1998 1997
-------------- ------ ------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Cash provided by operations:
Net income............................................... $ 13.9 $ 44.3 $ 57.8
Depreciation and amortization......................... 23.9 80.5 74.5
Deferred income taxes................................. 10.8 (24.0) 15.1
Minority interest earnings............................ 2.1 7.6 9.8
Other non-cash charges (credits) -- net............... (0.4) (1.0) 8.1
Changes in current assets and liabilities................ 18.0 (35.8) 14.6
------ ------ ------
Cash provided by operations...................... 68.3 71.6 179.9
------ ------ ------
Investing activities:
Capital expenditures..................................... (32.0) (143.8) (168.5)
Acquisition of Highlands Gas Corporation................. -- -- (179.4)
Acquisition of certain assets of Norcen.................. -- (83.2) --
------ ------ ------
Cash used by investing activities................ (32.0) (227.0) (347.9)
------ ------ ------
Financing activities:
Capital contributions by/(distributions to) Union Pacific
Resources Group Inc. ................................. (40.3) 168.8 186.1
Distributions to minority interest owners................ (1.5) (11.3) (20.2)
------ ------ ------
Cash provided by (used in) financing
activities..................................... (41.8) 157.5 165.9
------ ------ ------
Net change in cash and temporary investments............... (5.5) 2.1 (2.1)
Balance at beginning of period............................. 9.5 7.4 9.5
------ ------ ------
Balance at end of period................................... 4.0 9.5 7.4
------ ------ ------
Changes in current assets and liabilities:
Accounts receivable...................................... 35.7 13.1 1.4
Inventories.............................................. 12.7 (10.4) (15.2)
Other current assets..................................... 0.7 11.3 (5.2)
Accounts payable......................................... (29.4) (45.9) 30.5
Other current liabilities................................ (1.7) (3.9) 3.1
------ ------ ------
Total............................................ $ 18.0 $(35.8) $ 14.6
====== ====== ======
</TABLE>

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

F-46
<PAGE> 127

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 $1.1 million, $4.5 million
and $2.0 million for the quarter ended March 31, 1999, and for the years ended
December 31, 1998 and 1997, 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.

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 the amounts can

F-47
<PAGE> 128
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

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. Expenses for these services are not included in the
statements of income. 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.

F-48
<PAGE> 129
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

The following table summarizes product purchases, in volumes and dollars,
made by the UPFuels Division from UPR during the quarter ended March 31, 1999,
and each of the years ended December 31, 1998 and 1997:

<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998 1997
--------- ------ ------
(VOLUMES)
<S> <C> <C> <C>
Gas (MMcf/day).............................................. 846.2 923.1 860.8
Natural gas liquids (Mbbls/day)............................. 63.1 68.5 68.8
(MILLIONS OF DOLLARS)
Gas......................................................... $140.1 $630.1 $628.4
Natural gas liquids......................................... $ 43.3 $203.5 $281.3
</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>

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.

F-49
<PAGE> 130
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

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.

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.

F-50
<PAGE> 131
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

Components of income tax expense for the quarter ended March 31, 1999, and
the years ended December 31, 1998 and 1997 are as follows:

<TABLE>
<CAPTION>
1999 1998 1997
----- ------ -----
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current:
Federal.................................................. $(2,6) $ 47.4 $17.8
State.................................................... (0.1) 2.7 1.0
----- ------ -----
Total current.................................... (2.7) 50.1 18.8
Deferred:
Federal.................................................. 10.2 (22.7) 14.2
State.................................................... 0.6 (1.3) 0.9
----- ------ -----
Total deferred...................................... 10.8 (24.0) 15.1
----- ------ -----
Total............................................ $ 8.1 $ 26.1 $33.9
===== ====== =====
</TABLE>

A reconciliation between statutory and effective tax rates for the quarter
ended March 31, 1999, and the years ended December 31, 1998 and 1997 is as
follows:

<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<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.

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 $0.5
million for the quarter ended March 31, 1999, and $1.3 million and $1.1 million
for the years ended December 31, 1998 and 1997, respectively. Currently there is
no sublease income for the next five years or thereafter.

F-51
<PAGE> 132
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

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 $.7 million, $1.3
million and $1.2 million for the quarter ended March 31, 1999, and the years
ended December 31, 1998 and 1997, 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 $0.1 million, $1.9 million and
$0.6 million for the quarter ended March 31, 1999, and the years ended December
31, 1998 and 1997, 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 quarter ended March 31, 1999, and the years ended December 31,
1998 and 1997, compensation cost related to the allocation of ESOP shares to
participants' accounts was $0.4 million, $1.6 million and $1.4 million,
respectively, for the UPFuels Division.

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 no spending for the quarter ended March 31,
1999 and $1.2 million in 1998.

F-52
<PAGE> 133
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

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, 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

F-53
<PAGE> 134
UPFUELS DIVISION

NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED

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-54
<PAGE> 135

[DUKE ENERGY FIELD SERVICES LOGO]
<PAGE> 136

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The following table sets forth the costs and expenses, other than
underwriting discounts and commissions, payable by Duke Energy Field Services
Corporation in connection with the sale of common stock being registered. All
amounts are estimates except the SEC registration fee and the NASD filing fees.

<TABLE>
<S> <C>
SEC Registration fee........................................ $211,200
NASD fee.................................................... 30,500
NYSE initial listing fee.................................... *
Printing and engraving...................................... *
Legal fees and expenses..................................... *
Accounting fees and expenses................................ *
Transfer agent fees......................................... *
Miscellaneous expenses...................................... *
--------
Total............................................. *
========
</TABLE>

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

* To be provided by amendment.

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Section 145 of the Delaware General Corporation Law ("DGCL") provides that
a corporation may indemnify any person who was or is a party or is threatened to
be made a party to any threatened, pending or completed action, suit or
proceeding whether civil, criminal, administrative or investigative (other than
an action by or in the right of the corporation by reason of the fact that he is
or was a director, officer, employee or agent of the corporation, or is or was
serving at the request of the corporation as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees), judgments, fines and
amounts paid in settlement actually and reasonably incurred by him in connection
with such action, suit or proceeding if he acted in good faith and in a manner
he reasonably believed to be in or not opposed to the best interests of the
corporation, and, with respect to any criminal action or proceeding, had no
reasonable cause to believe his conduct was unlawful. Section 145 further
provides that a corporation similarly may indemnify any such person serving in
any such capacity who was or is a party or is threatened to be made a party to
any threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that he is
or was a director, officer, employee or agent of the corporation or is or was
serving at the request of the corporation as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees) actually and reasonably
incurred in connection with the defense or settlement of such action or suit if
he acted in good faith and in a manner he reasonably believed to be in or not
opposed to the best interests of the corporation and except that no
indemnification shall be made in respect of any claim, issue or matter as to
which such person shall have been adjudged to be liable to the corporation
unless and only to the extent that the Delaware Court of Chancery or such other
court in which such action or suit was brought shall determine upon application
that, despite the adjudication of liability but in view of all of the
circumstances of the case, such person is fairly and reasonably entitled to
indemnity for such expenses which the Delaware Court of Chancery or such other
court shall deem proper.

The company's certificate of incorporation and bylaws provide that
indemnification shall be provided for all current and former directors and may
be provided for all current or former officers to the fullest extent permitted
by the DGCL.

As permitted by the DGCL, the certificate of incorporation provides that
directors of the company shall have no personal liability to the company or its
stockholders for monetary damages for breach of fiduciary duty as a director,
except (1) for any breach of the director's duty of loyalty to the company or
its stockholders,

II-1
<PAGE> 137

(2) for acts or omissions not in good faith or which involve intentional
misconduct or knowing violation of law, (3) under Section 174 of the DGCL or (4)
for any transaction from which a director derived an improper personal benefit.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

The company has not sold any securities, registered or otherwise, within
the past three years, except as set forth below.

On December 8, 1999, the company issued 1,000 shares of its common stock to
Duke Energy Corporation ("Duke Energy") for $1,000. In so doing, the company
relied on the provisions of Section 4(2) of the Securities Act of 1933, as
amended (the "Securities Act"), in claiming exemption for the offering, sale and
delivery of such securities from registration under the Securities Act.

On December 16, 1999, Duke Energy, Phillips Petroleum Company ("Phillips")
and Duke Energy Field Services, LLC ("Field Services LLC") entered into a
Contribution Agreement (the "Contribution Agreement") pursuant to which Duke
Energy and Phillips, on March , 2000, contributed their respective midstream
natural gas assets to Field Services LLC, a subsidiary of the company, in
exchange for member interests in Field Services LLC and one-time cash payments.
Upon consummation of the offering contemplated by this registration statement,
the subsidiary ("Merger Subsidiary") that indirectly holds Phillips' interest in
Field Services LLC will be merged into the company, and, as a result, the
capital stock of Merger Subsidiary, all of which is owned by Phillips, will be
converted into shares of common stock of the company and the capital stock of
the company before the merger, all of which is owned by Duke Energy, will be
converted into new shares of common stock of the company. The exact allocation
between Duke Energy and Phillips of shares of common stock of the company issued
in the merger will be determined by the average of the closing prices of the
company's common stock on the New York Stock Exchange Composite Tape on the
stock's first five trading days. In so doing, the company relied on the
provisions of Section 4(2) of the Securities Act in claiming exemption for the
offering, sale and delivery of such securities from registration under the
Securities Act.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(A) EXHIBITS

II-2
<PAGE> 138

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.5* -- License Agreement dated as of , 2000 among
Duke Energy Corporation and Duke Energy Field Services
Corporation
10.6* -- Shareholders Agreement dated as of , 2000
among Duke Energy Natural Gas Corporation and Phillips
Petroleum Company
10.7 -- Contribution Agreement dated as of December 16, 1999
among Duke Energy Corporation, Phillips Petroleum Company
and Duke Energy Field Services, LLC (incorporated by
reference to Exhibit 2.1 to Duke Energy Corporation's
Form 8-K filed December 30, 1999)
10.8 -- NGL Output Purchase and Sale Agreement effective as of
January 1, 2000 between GPM Gas Corporation and Phillips
66 Company, a division of Phillips Petroleum Company, as
amended by Amendment No. 1 dated December 16, 1999
10.9* -- Sulfur Sales Agreement effective as of January 1, 1999
between Phillips 66 Company, a division of Phillips
Petroleum Company, and GPM Gas Corporation
21.1* -- Subsidiaries of the Company
23.1 -- Consent of Ernst & Young LLP
23.2 -- Consent of Deloitte & Touche LLP
23.3 -- Consent of Arthur Andersen LLP
23.5* -- Consent of Vinson & Elkins L.L.P. (included in Exhibit
5.1)
24.1 -- Power of Attorney (included in signature page)
27.1 -- Financial Data Schedule
99.1 -- Consent of Michael J. Panatier to Serve as Director dated
March 13, 2000
99.2 -- Consent of J.J. Mulva to Serve as Director dated March
10, 2000
</TABLE>

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

* To be filed by amendment.

(B) FINANCIAL STATEMENT SCHEDULE

No financial statement schedules are required to be included herewith or
they have been omitted because the information required to be set forth therein
is not applicable.

ITEM 17. UNDERTAKINGS.

The Registrant hereby undertakes:

(a) Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the Registrant pursuant to the provisions described
in Item 14, or otherwise, the Registrant has been advised that in the
opinion of the Securities and Exchange Commission such indemnification is
against public policy as expressed in the Act and is, therefore,
unenforceable. In the event that a claim for indemnification against such
liabilities (other than the payment by the Registrant of expenses incurred
or paid by a director, officer, or controlling person of the Registrant in
the successful defense of any action, suit or proceeding) is asserted by
such director, officer, or controlling person in connection with the
securities being registered, the Registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent, submit to
a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.

(b) To provide to the underwriter(s) at the closing specified in the
underwriting agreements, certificates in such denominations and registered
in such names as required by the underwriter(s) to permit prompt delivery
to each purchaser.

II-3
<PAGE> 139

(c) For purpose of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus filed as part
of this Registration Statement in reliance upon Rule 430A and contained in
the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1)
or (4) or 497(h) under the Securities Act shall be deemed to be part of
this Registration Statement as of the time it was declared effective.

(d) For the purpose of determining any liability under the Securities
Act of 1933, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.

II-4
<PAGE> 140
SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this registration statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Denver,
State of Colorado, on this 14th day of March, 2000.

Duke Energy Field Services
Corporation

By:
/s/ JIM W. MOGG
----------------------------------
Name: Jim W. Mogg
Title: Chairman of the Board,
President and Chief
Executive Officer
(Principal Executive Officer)

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints David D. Frederick and Martha B. Wyrsch or any of
them, his true and lawful attorney-in-fact and agent, with full power of
substitution, for him and in his name, place and stead, in any and all
capacities, to sign any and all amendments (including post-effective amendments)
to this Registration Statement and any additional registration statement
pursuant to Rule 462(b), and to file the same with all exhibits thereto, and
other documents in connection therewith, with the Securities and Exchange
Commission, granting unto said attorney-in-fact and agent full power and
authority to do and perform each and every act and thing requisite and ratifying
and confirming all that said attorney-in-fact and agent or his or her substitute
or substitutes may lawfully do or cause to be done by virtue hereof. Pursuant to
the requirements of the Securities Act of 1933, this Registration Statement has
been signed by the following persons in the capacities indicated on the dates
indicated:

Pursuant to the requirements of the Securities Act of 1933, as amended,
this registration statement has been signed below by the following persons in
the capacities and on the dates indicated below.

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>

/s/ JIM W. MOGG Chairman of the Board, March 14, 2000
- ----------------------------------------------------- President and Chief
Jim W. Mogg Executive Officer
(Principal Executive
Officer)

/s/ DAVID D. FREDERICK Chief Financial Officer March 14, 2000
- ----------------------------------------------------- (Principal Financial and
David D. Frederick Accounting Officer)

/s/ FRED J. FOWLER Director March 14, 2000
- -----------------------------------------------------
Fred J. Fowler

/s/ RICHARD B. PRIORY Director March 14, 2000
- -----------------------------------------------------
Richard B. Priory
</TABLE>

II-5
<PAGE> 141

INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
1.1* -- Form of Underwriting Agreement
2.1* -- Agreement of Merger dated as of , 2000
among Duke Energy Field Services Corporation and Phillips
Gas Company Shareholder, Inc.
3.1* -- Form of Amended and Restated Certificate of Incorporation
3.2* -- Form of Amended and Restated Bylaws
4.1* -- Form of Common Stock Certificate
5.1* -- Opinion of Vinson & Elkins L.L.P.
10.1* -- Employment Agreement dated as of , 2000
between Duke Energy Field Services Corporation and Mike
J. Panatier
10.2* -- Registration Rights Agreement dated as of
, 2000 among Duke Energy Corporation,
Phillips Petroleum Company and Duke Energy Field Services
Corporation.
10.3* -- Services Agreement dated as of March 14, 2000 by and
between Duke Energy Corporation, Duke Energy Business
Services, LLC, Pan Service Company, Duke Energy Gas
Transmission Corporation and Duke Energy Field Services,
LLC
10.4* -- Services Agreement dated as of , 2000 among
Phillips Petroleum Company and Duke Energy Field Services
Corporation
10.5* -- License Agreement dated as of , 2000 among
Duke Energy Corporation and Duke Energy Field Services
Corporation
10.6* -- Shareholders Agreement dated as of , 2000
among Duke Energy Natural Gas Corporation and Phillips
Petroleum Company
10.7 -- Contribution Agreement dated as of December 16, 1999
among Duke Energy Corporation, Phillips Petroleum Company
and Duke Energy Field Services, LLC (incorporated by
reference to Exhibit 2.1 to Duke Energy Corporation's
Form 8-K filed December 30, 1999)
10.8 -- NGL Output Purchase and Sale Agreement effective as of
January 1, 2000 between GPM Gas Corporation and Phillips
66 Company, a division of Phillips Petroleum Company, as
amended by Amendment No. 1 dated December 16, 1999
10.9* -- Sulfur Sales Agreement effective as of January 1, 1999
between Phillips 66 Company, a division of Phillips
Petroleum Company, and GPM Gas Corporation
21.1* -- Subsidiaries of the Company
23.1 -- Consent of Ernst & Young LLP
23.2 -- Consent of Deloitte & Touche LLP
23.3 -- Consent of Arthur Andersen LLP
23.5* -- Consent of Vinson & Elkins L.L.P. (included in Exhibit
5.1)
24.1 -- Power of Attorney (included in signature page)
27.1 -- Financial Data Schedule
99.1 -- Consent of Michael J. Panatier to Serve as Director dated
March 13, 2000
99.2 -- Consent of J.J. Mulva to Serve as Director dated March
10, 2000
</TABLE>

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

* To be filed by amendment.

<PAGE> 1

EXHIBIT 10.8

================================================================================

NGL OUTPUT PURCHASE AND SALE AGREEMENT

Between

GPM GAS CORPORATION

and

PHILLIPS 66 COMPANY, A DIVISION OF
PHILLIPS PETROLEUM COMPANY

JANUARY 1, 2000

================================================================================

<PAGE> 2

NGL OUTPUT PURCHASE AND SALE AGREEMENT

TABLE OF CONTENTS

<TABLE>
<CAPTION>
ARTICLE PAGE
- ------- ----

<S> <C>
I. Definitions...............................................................................................1
II. Term......................................................................................................4
III. Quantity..................................................................................................5
IV. Price.....................................................................................................10
V. Quality...................................................................................................12
VI. Settlement, Invoicing and Payment.........................................................................18
VII. Measurement, Sampling and Analysis........................................................................19
VIII. Custody, Title, and Risk of Loss..........................................................................22
IX. Dispute Resolution........................................................................................23
X. Force Majeure.............................................................................................26
XI Taxes.....................................................................................................27
XII. Notices...................................................................................................27
XIII. Records and Audit.........................................................................................28
XIV. Confidentiality...........................................................................................29
XV. Miscellaneous Provisions..................................................................................30
</TABLE>

Exhibits

Exhibit A Delivery Points
Exhibit B Specifications
Exhibit C Reference Prices
Exhibit D Transportation and Fractionation Variables
Exhibit E Provisions Regarding Benedum Analyzer
Exhibit F Form of Guaranty
Exhibit G Bushton Plant Systems

<PAGE> 3

NGL OUTPUT PURCHASE AND SALE AGREEMENT

THIS NGL OUTPUT PURCHASE AND SALE AGREEMENT ("Agreement") is made and
entered into effective as of the1st day of January, 2000 by and between PHILLIPS
66 COMPANY, a division of PHILLIPS PETROLEUM COMPANY, a Delaware corporation
("Buyer"), and GPM GAS CORPORATION, a Delaware corporation ("Seller"). Buyer and
Seller are sometimes referred to individually herein as a "Party" and
collectively as the "Parties."

W I T N E S S E T H:

WHEREAS, Seller owns or controls and has the right to dispose of certain
quantities of NGL's (as herein defined);

WHEREAS, Seller may from time to time acquire or develop additional
quantities of NGL's; and

WHEREAS, Seller desires to sell such NGL's to Buyer, and Buyer desires to
purchase the same from Seller.

NOW THEREFORE, in consideration of the mutual and dependent promises
contained herein, Seller and Buyer agree as follows:

ARTICLE I

DEFINITIONS

1.1 The following words and terms, when capitalized herein, shall have the
respective meanings set forth in this Article I:

(a) "Affiliate" means any company, corporation or other entity which, through
the ownership of stock or otherwise, directly or indirectly controls, is
controlled by, or is under common control with, another entity. An entity
shall be deemed to control another entity if it has the direct or indirect
right to select the management of such other entity.

(b) "Arbitration Notice" shall have the meaning set forth in Article IX.

(c) "Austin Region" means the Giddings Plant and the gas gathering systems
associated therewith located in Bastrop, Brazos, Burleson, Fayette, Grimes,
Lavaca, Lee and Washington counties in Texas, and such related counties
into which Seller or gatherers who are Affiliates of Seller may extend
their gas gathering systems in south central Texas from time to time.

(d) "Barrel" or "Bbl" means forty-two (42) U.S. gallons.

<PAGE> 4

(e) "Business Day" means any Day other than a Saturday, Sunday or legally
recognized holiday of the United States of America.

(f) "Calendar Quarter" means a period of three (3) Months commencing on the
first Day of January, April, July or October in any calendar year.

(g) "Condensate" means hydrocarbon drip, condensate, compression, and
stabilizer liquids (excluding slop oil) which are:

(i) condensed from natural gas that is produced in association with the
normal production of crude oil up to, and including, the crude oil
collection tanks; or

(ii) condensed from the gas phase associated with the normal production and
gathering of raw natural gas from the wellhead to the inlet of a
natural gas processing plant, including liquids collected and removed
at the inlet receiver.

(h) "Day" means a period of twenty-four (24) consecutive hours commencing at
7:00 a.m. central time (either standard or daylight savings, as
applicable).

(i) "Delivery Point" means each point of delivery described in Exhibit "A," any
point of delivery added to this Agreement pursuant to Section 3.5 and any
other mutually agreeable point of delivery.

(j) "Effective Date" shall have the meaning set forth in Article II.

(k) "Force Majeure" shall have the meaning set forth in Article X.

(l) "Gallon" means a U.S. gallon of two hundred thirty-one (231) cubic inches
of liquid corrected for temperature to Sixty Degrees Fahrenheit
(60(degree)F) and at the equilibrium vapor pressure of the liquid.

(m) "Month" means a period of time commencing on the first Day of a calendar
month and ending at the beginning of the first Day of the following
calendar month.

(n) "New Mexico Region" means the Artesia, Eunice and Linam Ranch Plants, and
the gas gathering systems associated therewith located in Chaves, Eddy, and
Lea counties in New Mexico, and Gaines and Loving counties in Texas, and
such related counties into which Seller or its Affiliates may extend their
New Mexico gas gathering systems from time to time.

(o) "New Plant" means a gas processing plant not described on Exhibit "A" at
which Seller delivers or intends to deliver natural gas, where such natural
gas originates in whole or in part in the counties where natural gas is
currently gathered and supplied to Plants which are described on Exhibit
"A," or into which the same may be extended.

-2-

<PAGE> 5

(p) "NGL" or "NGL's" means the raw mixture of natural gas liquids (consisting
predominantly of ethane (C2), propane (C3), isobutane (i-C4), normal butane
(n-C4) and pentanes plus (C5+), each of which are hereinafter sometimes
referred to singularly as an "NGL Component" and collectively as "NGL
Components") which are (i) condensed, adsorbed or absorbed from or
separated out of the natural gas when processed in the Plants, or (ii)
delivered in the form of Y-2 Product.

(q) "NGL Component Price" means the Monthly price in dollars per Barrel for the
NGL Components delivered at each Delivery Point, as provided in Article IV.

(r) "Off-Specification NGL" has the meaning set forth in Article V.

(s) "Oklahoma Region" means the Kingfisher, Okarche, Mooreland, Cimarron, and
Binger Plants, and the gas gathering systems associated therewith located
in Alfalfa, Blaine, Caddo, Canadian, Cleveland, Custer, Dewey, Ellis,
Garfield, Grady, Kingfisher, Logan, Major, Oklahoma, Roger Mills, Woods and
Woodward counties of Oklahoma, and such related counties into which Seller
or its Affiliates may extend their central and western Oklahoma gas
gathering systems from time to time.

(t) "Plants" means the gas processing plants and other facilities described in
Exhibit "A."

(u) "Panhandle Region" means the Dumas, Rock Creek, and Sherman-Hansford,
Plants (excluding the Bushton Plant), the Sneed and Gray compressor
stations, and the gas gathering systems of Seller and its related
Affiliates associated therewith located in Clark, Comanche, Meade, Morton
and Seward counties in Kansas, and Beaver, Cimarron, Ellis, Harper, Texas,
and Woods counties in Oklahoma, and Carson, Dallam, Gray, Hansford,
Hartley, Hemphill, Hutchinson, Lipscomb, Moore, Ochiltree, Potter, Roberts,
Sherman, and Wheeler counties in Texas, and such related counties into
which Seller or its Affiliates may extend their Oklahoma and Texas
Panhandle, northwest Oklahoma, and southwest Kansas gathering systems from
time to time.

(v) "Preexisting Delivery or Sale Obligations" means contracts entered into
prior to Seller's acquisition of an interest in a gas gathering or
processing plant asset or prior to Seller's arrangement of deliveries of
natural gas to a New Plant, that require that (i) the NGL's produced from
gas gathered in such system, delivered to a New Plant and processed into
NGL's, or (ii) the NGL's from such New Plant, be delivered or sold to a
party other than Buyer.

(w) "Region" shall mean the Austin Region, the New Mexico Region, the Oklahoma
Region, the Panhandle Region, and the West Texas Region, respectively.

(x) "Senior Management" means, with respect to Buyer, the Executive Vice
President in charge of Buyer's Downstream Division and, in the case of
Seller, its President (or their respective functional successors).

-3-

<PAGE> 6

(y) "West Texas Region" means the Fullerton, Goldsmith, Spraberry, and Benedum
Plants and the gas gathering systems associated therewith located in
Andrews, Crane, Crockett, Dawson, Ector, Gaines, Glasscock, Howard, Martin,
Midland, Mitchell, Pecos, Reagan, Sterling, Terry, Upton, Ward, Winkler,
and Yoakum counties in Texas, and such related counties into which Seller
may extend its gas gathering system from time to time.

(z) "Year" means a period of twelve (12) consecutive Months commencing on the
Effective Date, and shall also include each successive twelve (12) Month
period during the term hereof.

(aa) "Y-1 Products " means NGL's described in clause (i) of the definition of
the term "NGL's."

(bb) "Y-2 Products" means Condensate from the Panhandle Region.

References herein to Articles, Sections and Exhibits shall mean the Articles and
Sections of, and the Exhibits attached to, this Agreement. All Exhibits
mentioned in this Agreement are incorporated by reference as if set out herein
in full.

ARTICLE II

TERM

2.1 PRIMARY TERM. This Agreement shall become effective on January 1, 2000 (the
"Effective Date"), regardless of the date of execution, and shall continue for a
primary term of fifteen (15) Years thereafter.

2.2 RENEWAL TERMS; NOTICE OF TERMINATION. The term shall be extended after the
primary term for successive five (5) Year terms, unless written notice of
termination is delivered by either Party to the other not less than three (3)
Years prior to the end of the primary term or any succeeding five (5) Year term.

2.3 PHASE DOWN PERIOD. Commencing with the first year following the term in
which notice of termination has been given, the Phase Down Period shall begin.
The Phase Down Period shall continue for four (4) years, and shall terminate on
the first day of the fifth Year. Not later than one (1) year prior to the
beginning of the Phase Down Period, the Parties shall negotiate with respect to
the quantities of Products to be sold and delivered during each successive year.
In the event that the Parties are unable to agree with respect thereto, the
percentage of the NGL's owned, controlled or otherwise available for sale which
are to be sold and delivered hereunder during each Year of the Phase Down period
shall be equal to the percentages shown in the following table:

-4-

<PAGE> 7

<TABLE>
<CAPTION>
Year of Phase Down Percentage
Period
------------------ ----------
<S> <C>
1 80%
------------------ ----------
2 60%
------------------ ----------
3 40%
------------------ ----------
4 20%
------------------ ----------
</TABLE>

ARTICLE III

QUANTITY

3.1 SALE AND PURCHASE. Subject to the other provisions of this Agreement, Seller
shall deliver and sell, and Buyer shall receive and purchase, each Month one
hundred percent (100%) of the NGL's owned or controlled, or otherwise available
for sale by Seller, and available at the Delivery Points listed in Exhibit A;
provided, Buyer shall not be obligated to purchase any quantity in excess of the
lesser of (i) the quantities described in Seller's forecasts given under Section
3.3(a) and (ii) the quantity purchased by Buyer from Seller during the preceding
Year. Deliveries and receipts of NGL's will be in approximately uniform and even
quantities throughout each Month.

3.2 EXCEPTIONS. (a) Notwithstanding the provisions of Section 3.1, (i) Seller
shall have the right to deliver NGL's produced at the Plants in kind to
suppliers or their nominees pursuant to arrangements in the normal course of
business in response to competitive market conditions to attract and maintain
natural gas supplies for processing at the Plants, (ii) Seller may exclude from
the volumes of NGL's that would otherwise be deliverable hereunder a volume of
NGL's equal to 4% (four percent) of the total volume of all NGL's which would be
sold to Buyer by Seller from Plants in the New Mexico Region and the West Texas
Region but for the provisions of this Section 3.2 (a) (ii), and (iii) Seller may
sell to others the volumes of NGL's which Buyer does not elect to take under
Section 3.3(d) or otherwise declines or fails to take, which volumes may be
delivered by Seller to alternate purchasers from any Delivery Point. Deliveries
of the volumes described in Section 3.2 (a) (ii) may be made only from the
Eunice and Linam Ranch Plants, in the case of the New Mexico Region, and from
the Fullerton Plant, in the case of the West Texas Region.

(b) Also excluded from commitment under this Agreement for its term are NGL's
derived from the gas production attached to the gathering systems committed
under that certain contract dated as of December 28, 1995, between Enron
Anadarko Gathering Corporation ("Enron Anadarko") and Enron Gas Processing
Company (the Enron Anadarko interest thereunder was assigned to Seller as of
December 31, 1995, and the Enron Gas Processing Co. interest is now held by K N
Processing, Inc.) (the "Bushton Agreement"). Seller warrants that it is not
directly or indirectly currently delivering gas under the Bushton Agreement
except by means of the

-5-

<PAGE> 8

gathering systems described in Exhibit G. Seller shall not directly or
indirectly divert into the gathering systems described in Exhibit G, for
delivery under the Bushton Agreement any gas Seller is not currently delivering
into such systems from Seller's Panhandle and Oklahoma gathering systems. Upon
termination of the Bushton Agreement Seller will evaluate its gathering and
processing alternatives for gas delivered under the Bushton Agreement in good
faith. If in the judgment of Seller it is most economically feasible, Seller
will commence integration and delivery of this gas into its Panhandle and
Oklahoma gathering systems, for ultimate delivery for processing in Plants or
New Plants in the Panhandle and Oklahoma Regions. Seller will not be obliged to
make capital expenditures in excess of Two Million Dollars ($2,000,000) to
integrate Exhibit G systems into its other systems.

(c) Seller covenants to Buyer that it will not enter into business combinations,
contracts or agreements, or otherwise modify its normal business practices,
which have as their purpose or effect the reduction or diversion of the
quantities of NGL's to be delivered and sold by Seller to Buyer hereunder (by
the diversion of raw gas supplies out of any Region, or otherwise), or any
circumvention of Seller's other obligations hereunder.

3.3 DELIVERY SCHEDULING; MAINTENANCE. (a) Seller shall notify Buyer, not later
than sixty (60) Days prior to the commencement of each Year, as to Seller's
forecast of the quantities Seller will have available for delivery to Buyer at
each Plant and at each New Plant and the period during which Seller anticipates
that deliveries will be curtailed from any Plant or New Plant by reason of
planned maintenance or other circumstances. Seller shall thereafter routinely
notify Buyer during such Year with respect to material variations (in excess of
10% at any Plant) in daily NGL production rates from the yearly forecast. Buyer
acknowledges that any such forecasts provided by Seller are estimates only, and
that the actual quantities delivered to Buyer may vary materially from such
estimates.

(b) Seller shall notify Buyer as soon as reasonably possible after it becomes
aware of any planned maintenance or planned temporary shutdown of any of its
Plants or related facilities which may be reasonably expected to limit Seller's
ability to deliver NGL's hereunder; provided, such notice shall be given to
Buyer at least one (1) month prior to any such planned maintenance or planned
temporary shutdown.

(c) Seller shall similarly provide Buyer, as soon as reasonably practicable,
notice of any other maintenance and shutdowns having a similar effect. Each such
notice shall specify the duration of any the maintenance period or temporary
shutdown, and the NGL quantity to be affected, as reasonably estimated by
Seller. During any such period, Buyer shall be free to use the NGL
transportation capacity not used for the receipt of NGL's from Seller for the
receipt and carriage of NGL's from others, provided, at the end of any period of
such maintenance or temporary shutdown, the delivery of NGL's by Seller and
purchases from Buyer shall recommence.

(d) On the basis of the forecast provided by Seller to Buyer pursuant to Section
3.3(a), Buyer shall notify Seller, not later than thirty (30) days prior to the
commencement of each Year, as to the quantity of NGL's Buyer will receive at
each Plant, consistent with Section 3.1 above. Buyer's notice shall also set
forth the period during which Buyer anticipates that receipts will be

-6-

<PAGE> 9

curtailed from any Plant by reason of planned maintenance of its facilities or
other circumstances during such Year. Buyer shall thereafter routinely notify
Seller during such Year with respect to material variations in such forecast.
Seller acknowledges that any such forecasts provided by Buyer are estimates only
and that actual capacity may vary from such estimates. Buyer shall not have any
obligation to accept quantities beyond its existing pipeline capacity, taking
into account operational constraints and Buyer's other NGL purchase obligations.
Buyer shall have no obligation to add pipeline, pumping, fractionation or
associated facilities, or to increase the capacities of existing facilities, in
order to receive additional volumes of NGL produced by Seller.

(e) Buyer shall notify Seller as soon as reasonably possible after it becomes
aware of any planned maintenance or planned temporary shutdown of any of its NGL
pipelines or related facilities which may be reasonably expected to limit
Buyer's ability to take NGL's hereunder; provided, such notice shall be given to
Seller at least one (1) month prior to any such planned maintenance or planned
temporary shutdown. Buyer shall similarly provide Seller, as soon as reasonably
practicable, notice of any other maintenance and temporary shutdowns having a
similar effect. Each such notice shall specify the duration of any such
maintenance period or temporary shutdown and the quantity to be affected, as
reasonably estimated by Buyer. During any such period, Seller shall be free to
sell and deliver to third parties quantities of NGL's that would otherwise be
deliverable to Buyer hereunder; provided, at the end of any period of such
maintenance or temporary shutdown, the delivery and receipt of any such volumes
shall recommence.

(f) Buyer and Seller will reasonably cooperate with each other to the greatest
extent practicable to schedule planned maintenance and other planned outages
simultaneously in order to minimize overall down time.

3.4 NEW PLANTS; ADDITIONAL NGL'S SOURCES. Buyer shall have the right to purchase
NGL's that Seller produces, controls or otherwise has available for sale at New
Plants as indicated below. Seller shall provide written notice to Buyer of its
intent to have NGL's available for sale from any such New Plant. Such notice
shall be provided as soon as reasonably possible upon Seller's becoming aware
that such volumes are or will be available. The notice shall include an estimate
of the NGL's expected to be available for sale for a five-year period from the
New Plant and information about any Preexisting Delivery or Sale Obligations.
Upon receipt of any such notice from Seller the following shall apply:

(i) Except as provided in clause (ii) of this Section 3.4, Buyer may notify
Seller within sixty (60) Days that it wishes to acquire such volumes
and will pay the expense of connecting new or additional pipeline
facilities or otherwise arranging for the receipt of such volumes
through existing facilities. Upon Seller's receipt of Buyer's notice,
the volumes of NGL's available from such New Plant shall be committed
for sale and delivery under this Agreement. The Market Reference Price
for such volumes shall be the Market Reference Price applicable to the
Region in which, or which is geographically nearest, the location of
the New Plant, and the Transportation and Market Frac Prices to be
utilized in the calculation of the net price payable shall be the
prices applicable to the Plant geographically nearest the New Plant.

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<PAGE> 10

(ii) If the New Plant has an existing pipeline and connection by means of
which such NGL's may be transported, Buyer may purchase the volumes
available on the terms described in clause (i) of this Section 3.4;
provided, the Transportation Price applicable to determination of the
net purchase price shall be equal to the tariff payable in respect of
shipments on such pipeline. The Market Reference Price and Market
Frac Price shall be as provided in clause (i) of this Section 3.4.

(iii) In the event that Buyer does not notify Seller that it wishes to
purchase such NGL's pursuant to clauses (i) or (ii) of this Section
3.4, and no NGL pipeline and connection is readily available for the
transportation of such volumes into Buyer's NGL gathering system,
Seller may negotiate for the sale of the New Plant NGL volumes with
Buyer and other potential NGL purchasers on mutually agreeable
prices, terms and conditions of sale. If such negotiations do not
result in an agreement between Buyer and Seller for the affected
volumes of NGL's, prior to entering into any binding agreement with
another purchaser for the sale of the New Plant volumes, Seller shall
offer in writing to sell them to Buyer at the prices and upon the
terms and conditions which Seller is willing to accept that have been
offered by a competing purchaser. Seller's notice shall include all
of the terms and conditions of the proposed alternate sale agreement.
Buyer shall then have the option, exercisable for thirty (30) days
following the date of Buyer's receipt of Seller's notice of the
competing proposal to purchase the affected New Plant volumes by
agreeing to match all price and other terms and conditions of sale
contained in such competing proposal, except that the provisions of
Article IX of this Agreement shall be deemed to have been included
and shall control over any conflicting dispute resolution terms of
the competing offer. If Buyer desires to match the competing offer,
Buyer shall so notify Seller in writing during the option period, and
the offer from Seller and its acceptance from Buyer through the
option exercise shall become the new agreement between the parties
concerning the sale and purchase of the affected New Plant NGL's.

Upon the commitment of NGL's pursuant to subsection (i) or (ii) of this Section
3.4, a Delivery Point for the New Plant will be added to Exhibit A with the
initial Transportation and Fractionation variables being as hereinabove
provided. If a New Plant is added to this Agreement under this Section, of if
any quantities are sold from a New Plant pursuant to clause (iii) above, Seller
shall not allow the term of any Preexisting Delivery or Sale Obligations
applicable to such New Plant to be extended without Buyer's consent unless under
such Preexisting Delivery or Sale Obligations the other Party has the unilateral
right to cause such extension to occur. If Buyer elects not to acquire NGL's
from a New Plant incident to the exercise of its rights under this Section 3.4,
Seller shall be free to sell such NGL's elsewhere.

3.5 INCREASES IN NGL PRODUCTION CAPACITY. (a) In the event that Seller
anticipates a material increase in the quantity of NGL's available for sale at
any given Plant, then Seller shall provide Buyer with written notice of such
increased quantity and the date on which the same will

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become available. Within sixty (60) Days after the receipt of Seller's notice,
Buyer shall notify Seller in writing of: (i) whether or not Buyer desires to
take such increased quantity, and (ii) the nature and extent of any additional
facilities which are required to be built for Buyer to receive the same.

(b) If Buyer notifies Seller within such sixty (60) Day period that Buyer
desires to receive such increased quantity at such Plant and no material
incremental facilities are required, then such increased quantity shall be
committed to this Agreement as and when it becomes available.

(c) If Buyer notifies Seller within such sixty (60) Day period that Buyer
desires to receive such increased quantity at such Plant and incremental
facilities are required, then the Parties shall negotiate to determine the
arrangements which will be applicable to such incremental facilities (including,
but not limited to, responsibility for construction and maintenance costs, the
time period required to design, build and place the facilities into service, and
any specific throughput or capital recovery commitments, if any). If the Parties
are able to reach agreement on such incremental facility arrangements within
sixty (60) Days of Seller's receipt of Buyer's notice, then the Parties shall
execute any necessary documents evidencing such agreement and such increased
quantity shall be committed to this Agreement as and when they become available.
If the Parties are unable to reach agreement on such incremental facility
arrangements within sixty (60) Days of Seller's receipt of Buyer's notice, then
such a determination with respect to such arrangements shall be made pursuant to
Section 9.1 if requested by either Party.

(d) If Buyer notifies Seller within such sixty (60) Day period that Buyer does
not presently desire to receive such increased quantities at such Plant, and no
incremental facilities are required to make delivery of such increased
quantities from such Plant (e.g. a third party pipeline has available capacity),
then Seller shall have the right to make alternate arrangements for the delivery
and sale of such increased quantities for a reasonable period of time beginning
on the date at which such increased quantities become available to Seller and
continuing through the next point in time when new Transportation and Market
Frac prices become effective for such Plant pursuant to Section 4.5; provided,
such alternate arrangements may extend for a period up to, but not in excess of,
three (3) years if necessary to the making of such arrangements. At such point
in time at which the Transportation and Market Frac prices for such Plant are
being negotiated pursuant to Section 4.5 (or upon the expiration of Seller's
alternate sales arrangements, if later), Buyer shall notify Seller in writing if
Buyer desires to purchase and receive such increased quantities at such Plant.
If Buyer provides such notice to Seller the increased quantity shall thereafter
be committed to this Agreement beginning on the first Day of the Year in which
such new price becomes effective (or upon the expiration of Seller's alternate
sales arrangements, if later). If Buyer does not provide such notice to Seller
within such time period, then such increased quantities may thereafter be
released from this Agreement and Seller shall have the right to make any
arrangements its deems necessary for the delivery and sale thereof.

(e) If Buyer fails to respond to Seller within sixty (60) Days of Buyer's
receipt of Seller's initial notice of increased quantities, then such increased
quantity may be released from this Agreement and Seller shall have the right to
make any arrangements it deems necessary for the delivery and sale thereof.

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<PAGE> 12

3.6 NGL TRANSPORTATION CAPACITY. Buyer shall have the first right to use the
existing and available capacity of common carrier pipelines at the Delivery
Points specified for each Region to the extent necessary to receive and buy the
required quantity of NGL's from Seller pursuant to this Agreement.

3.7 PLANT, PIPELINE, AND OTHER FACILITIES CHANGES AND SHUTDOWNS; UNECONOMICAL
OPERATIONS. Nothing herein shall be construed as (i) prohibiting Seller from
reconfiguring or enlarging its Plants, or curtailing or terminating, the
operation thereof, or (ii) prohibiting Buyer from reconfiguring or enlarging its
NGL pipeline, gathering or fractionation facilities, or curtailing or
terminating the operation thereof where, in either such case, the same is in the
reasonable judgment of the Party owning such facilities, required by economic or
operating conditions. Incident to the sale or other disposition of any of its
Plants, Seller shall assign this Agreement in part to the asset purchaser
insofar as it applies to the affected Plant or Plants, or otherwise require that
the purchaser of such Plant(s) agree that Buyer shall have a continuing right to
purchase the NGL's produced therefrom on the same terms and conditions as apply
to the sale and purchase of NGL's hereunder; provided, no such assignment or
other arrangements shall relieve Seller of any of its obligations hereunder
except as stated in Section 15.4.

ARTICLE IV

PRICE

4.1 GENERAL PRICE FORMULA. Prices payable hereunder shall be based on the number
of Barrels of each NGL Component delivered each Month. Except as provided in
Section 4.2, for each NGL Component Barrel sold and delivered by Seller to Buyer
each Month, Buyer shall pay to Seller a price determined under the following
formula:

NGL Market
Component = Reference x 0.42 - T&F Fee,
Price, $/Bbl Price, Cents/Gal $/Bbl

Where:

The Market Reference Price is the OPIS Price for the NGL Component in
question, determined as provided in Section 4.3; and

The T&F Fee is the sum of the Transportation and Market Frac prices
applicable to the Region and NGL Component for which the calculation is
being made, as set forth in Exhibit D.

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<PAGE> 13

4.2 PANHANDLE REGION Y-2 PRODUCT PRICE. For each NGL Component Barrel of
pentanes plus sold by Buyer to Seller and delivered into the Panhandle Region
Y-2 Product system, Buyer shall pay to Seller a price determined under the
following formula:

NGL Market
Component = Reference - T&F Fee,
Price, $/Bbl Price, $/Bbl; $/Bbl

Where:

The Market Reference Price is the WTI NYMEX Price, determined as provided in
Section 4.4; and

The T&F Fee is the sum of the Transportation and Market Frac prices
applicable to Y-2 pentanes plus under the heading "NGL Component" in the
Panhandle Region, as set forth in Exhibit D.

4.3 OPIS PRICE. The OPIS Price for each NGL Component is the arithmetic average
of the midpoints of the daily high and low quotations applicable to the NGL
Component and Region in question, determined from Exhibit C, and as reported by
Oil Price Information Service ("OPIS"), on each Day during the Month of delivery
for which such price is quoted using the "Any Current Month" column. The
arithmetic average shall be expressed in U.S. Dollars to five (5) decimal places
(for example $0.34567). Where Exhibit C indicates that more than one quotation
category is to be used for the pricing of any NGL Component, each category shall
be used to the extent indicated.

4.4 WTI NYMEX PRICE. The WTI NYMEX Price is the arithmetic average of the prompt
Month settlement prices for West Texas Intermediate Crude Oil ("WTI") futures
contracts on the New York Mercantile Exchange ("NYMEX") quoted on each Day
during the Month of delivery, expressed in U.S. Dollars to five (5) decimal
places. The "prompt Month," for purposes hereof, is the earliest Month for which
a settlement price is quoted (ordinarily the Month following the Month of
delivery in the case of settlement prices quoted during the first twenty (20)
Days of the Month of delivery, and the second Month following the Month of
delivery in the case of settlement prices quoted during the remaining Days in
the Month of delivery).

4.5 RENEGOTIATIONS OF TRANSPORTATION AND MARKET FRAC PRICES. Not more frequently
than once each Year, beginning with the Year commencing on the Second (2nd)
anniversary of the Effective Date, the Transportation and Market Frac prices
described in Exhibit D may be adjusted pursuant to this Section 4.6. Such
adjustment shall be made upon the giving of notice by either Party to the other
not later than one hundred twenty (120) Days prior to the first (1st) Day of the
Year in which such adjustment is to apply. The Parties shall thereupon attempt
to agree with respect to the revised amounts, which shall be applicable with
respect to the pricing of deliveries commencing on the first (1st) Day of the
following Year. In the event that the Parties are unable to reach agreement
prior to the first (1st) Day of the Month immediately preceding the beginning of
such Year, then the Parties shall resolve any disputes or differences regarding
either

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<PAGE> 14

any Transportation price, or any Market Frac price, or both, pursuant to the
dispute resolution procedures described in Section 9.1. Pending renegotiation,
or resolution pursuant to the procedures described in Section 9.1, the prices
previously in effect shall continue to be paid on an interim basis, with
retroactive adjustments and resulting payments to be made promptly following
establishment of the new pricing criteria.

4.6 MARKET PRICE QUOTATION TERMINATIONS AND CHANGES. (a) In the event that OPIS
should cease publication of the price quotations used for any NGL Component, or
in the event that the trading of WTI futures contracts on the NYMEX should
cease, the Parties shall promptly agree upon an alternate source of price
quotations to be utilized, which source shall be capable of being applied in a
manner that will produce prices which fairly represent the value of the NGL at
the applicable pricing point or market reference point for which the original
information is no longer available. In the event that the Parties are unable to
agree with respect to the same within thirty (30) Days, the selection of a new
price source, together with its method of application, shall be determined
pursuant to the provisions of Section 9.1.

(b) In the event either Party believes in good faith that (i) the applicable
OPIS Price, or any successor to the OPIS Price established hereunder for any NGL
Component is no longer reflective of the market price for such NGL Component at
the pricing point or market reference point to which such OPIS Price, or
successor to such OPIS Price, applies, or (ii) the WTI NYMEX Price or any
successor to the WTI NYMEX Price established hereunder is no longer reflective
of the market price for sweet crude oil in the mid continent region of the
United States, such Party shall so notify the other Party. The Parties shall
then promptly agree upon an alternate source of price quotations to be used,
which source shall be capable of being applied in a manner that will produce
prices which fairly present the value of (x) the applicable NGL at the
applicable market reference point or (y) sweet crude oil in the mid continent
region of the United States, as applicable. In the event the Parties are unable
to agree to the same within thirty (30) Days, the selection of a new price
source, together with its application, shall be determined pursuant to the
provisions of Section 9.1. Neither Party may seek any selection of a new price
source for any given Market Reference Price pursuant to this Section 4.5(b) more
frequently that once in any period of two (2) Years.

ARTICLE V

QUALITY

5.1 GENERAL QUALITY REQUIREMENT; DELIVERY PRESSURE. Without prejudice to the
provisions of Article VI, the NGL's delivered by Seller to Buyer under this
Agreement shall conform at all times to the specifications set forth in Exhibits
B-1 and B-2, and shall be delivered at a pressure sufficient to effect delivery
at the Delivery Points; provided however, Seller shall not deliver NGL at a
given Delivery Point at a pressure in excess of the applicable maximum pressure
for such Delivery Point indicated in Exhibit A. In those instances in which
Seller delivers NGL's to Buyer at Delivery Points connected to facilities owned
and operated by parties other than Buyer or its Affiliates, the NGL's so
delivered shall conform to the specifications imposed by such parties. Whether
any NGL conforms to such specifications shall be determined pursuant to this

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<PAGE> 15

Article V and Article VII. Any NGL's not so conforming shall be deemed
Off-Specification NGL's.

5.2 QUALITY DETERMINATION METHODS. Except as provided in Sections 5.5 and 5.6
regarding free water, the quality characteristics of the NGL's at any given
Delivery Point shall be determined by Buyer (a) through laboratory analysis of
hydrocarbon composite samples associated with each such inspection location, (b)
by field testing of random spot samples, and (c) by laboratory analysis of
random spot samples.

(i) TESTS OF COMPOSITE SAMPLES. If laboratory analysis of a composite
sample from any inspection location results in a finding that the
sample fails to meet the product specifications set forth in Exhibit
B-1 in the case of Y-1 Product, or Exhibit B-2 in the case of Y-2
Product, then the NGL's delivered at such inspection location shall be
deemed to be Off-Specification NGL's. The number of Barrels of NGL's
deemed to be Off-Specification NGL's shall be equal to the total
number of Barrels indicated by flow measurement readings over the time
period during which such composite sample was collected (ordinarily
approximately 15 days).

(ii) FIELD TESTING - SPOT SAMPLES. If any field testing of any spot sample
at an inspection location results in a finding that the sample fails
to meet the specifications for corrosion, product temperature, color
or deleterious substances (including suspended solids/particulates),
the NGL's so delivered shall also be deemed to be Off-Specification
NGL's. The number of Barrels of NGL's deemed to be Off-Specification
NGL's shall be equal to the total number of Barrels of NGL's delivered
at such inspection location from the date on which the last conforming
sample was taken at such inspection location to the date on which the
non-conforming sample was obtained, but not in excess of fifteen (15)
days prior to the date on which such sample was obtained:.

(iii) LABORATORY TESTING - SPOT SAMPLES If laboratory testing of any spot
sample of NGL's taken by Buyer at an inspection location results in a
finding that the sample fails to meet any of the specifications other
than those characteristics tested in the field pursuant to Section
5.2(ii), the NGL's so delivered shall be deemed to be
Off-Specification NGL's. Subject to the succeeding sentences of this
clause 5.2(iii), number of Barrels of NGL's deemed to be
Off-Specification NGL's shall be equal to the number of Barrels
delivered during the period beginning on the date on which such spot
sample was taken, and ending on the date on which the next spot sample
at such location conforms to the specification. Promptly upon
determining that any sample fails to meet the specifications, Buyer
shall advise Seller of the same. Seller shall then use all reasonable
efforts to correct the circumstances causing such sample to be off
specification, and shall test for the characteristics that have caused
Buyer's sample to be off-specification. When Seller has determined, in
good faith, that such circumstances have been corrected, as evidenced
by Seller's tests, it shall so notify Buyer, and Buyer shall once
again obtain a spot sample from the same inspection location. In the
event

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that such sample is determined to be on-specification, then such NGL's
shall be deemed to have been Off-Specification NGL's only from the
date on which the original sample was taken up to the date of Seller's
notice that it has corrected the circumstances causing the same to be
off specification.

5.3 QUALITY ADJUSTMENT FEE. Without prejudice to Buyer's other rights and
remedies hereunder, Buyer shall have the right to reject any Off-Specification
NGL. In the event that Buyer accepts delivery of any Off-Specification NGL,
Buyer shall deduct, from the price that would otherwise be payable if such NGL
had conformed to the requirements of Article 5.1, a quality adjustment fee equal
to fifty cents ($0.50) for each Barrel of Off-Specification NGL delivered;
provided however, in the event the Off-Specification NGL is delivered into a
third party pipeline at a Delivery Point and such third party pipeline imposes a
fee or other charge as a result of such Off-Specification NGL, no such quality
adjustment fee shall be assessed by Buyer, but Seller shall be responsible for
any third party pipeline fee or charge pursuant to Section 5.4 below. The
quality adjustment fee is not imposed as a penalty, but in recognition of the
facts that (a) the determination of the actual depreciation in value experienced
would be difficult or impossible to determine, and (b) the Parties have agreed
that the amount of such deduction is reasonable. Acceptance of Off-Specification
NGL, and/or the payment or deduction of the quality adjustment fee, shall not
constitute a waiver of Buyer's right to require that all future deliveries meet
the quality specification requirements of this Agreement, nor shall the
occurrence of such events constitute a license to Seller to make further
deliveries of Off-Specification NGL.

5.4 INDEMNIFICATION. (a) Without prejudice to Section 5.3 but subject to other
provisions of this Section 5.4, as to all Off-Specification NGL's for which
Buyer elects to accept delivery, Seller shall protect, indemnify, defend, and
hold Buyer, its Affiliates (other than Seller), and their respective directors,
officers, and employees (the "Buyer Indemnitees") harmless from and against any
and all claims, debts, suits, costs (including legal fees and court costs),
expenses, liabilities and causes of action threatened or asserted by any party
other than Buyer or Buyer's Affiliates (collectively "Third Party Claims") and
which are associated with or attributable to the delivery of Off-Specification
NGL's. The foregoing indemnity, defense and hold harmless obligations shall
apply irrespective of whether Seller at Buyer's request or Buyer has delivered
Off-Specification NGL's to the third party asserting it has suffered damage,
costs and expenses (including third party NGL pipeline carriers, fractionation,
storage or similar facilities imposing fees or other charges or otherwise
seeking the recovery of expenses, costs or damages).

(b) The following limitations apply to Seller's obligations under this Section
5.4:

(i) Buyer's rights are limited to Third Party Claims attributable to
damage occurring downstream of the Delivery Points and up to and
including the finished NGL storage facilities associated with any NGL
fractionation facilities, and shall not extend to Third Party Claims
attributable to damage downstream of such finished NGL storage
facilities;

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<PAGE> 17

(ii) Seller will have no duty of indemnification for claims, debts, suits,
costs, (including legal fees and court costs), expenses and
liabilities resulting from spillage or mishandling of NGL's downstream
from the Delivery Points, or with respect to matters not arising from
the off quality nature of NGL's delivered by Seller; and

(iii) the quality adjustment fees deducted from payments to Seller or
otherwise collected by Buyer under this Agreement in respect of the
Off-Specification NGL's that caused such Third Party Claims to arise
shall be deducted from any amounts due from Seller under this Section
5.4.

(c) Buyer, Buyer's Affiliates and their respective directors, officers, agents
and employees are the "Indemnified Party" and Seller is the "Indemnifying Party"
for purposes of this subsection. All Claims by the Indemnified Party under this
Section shall be asserted and resolved as follows:

(i) In the event of the assertion of any Third Party Claim which could
give rise to damages for which the Indemnifying Party could be liable
to an Indemnified Party under this Agreement, the Indemnified Party
shall with reasonable promptness send to the Indemnifying Party, a
written notice specifying the nature and amount or estimated amount
thereof (which amount or estimated amount shall not be conclusive of
the final amount, if any, of such claim, demand or proceeding) (a
"Claim Notice"); provided, that a delay in notifying the Indemnifying
Party shall not relieve the Indemnifying Party of its obligations
under this Agreement except to the extend that (and only to the extent
that) such failure shall have caused the damages for which the
Indemnifying Party is obligated to be greater than such damages would
have been had the Indemnified Party given the Indemnifying Party
timely notice.

(ii) In the event of a Third Party Claim, the Indemnifying Party shall be
entitled to appoint counsel of the Indemnifying Party's choice at the
expense of the Indemnifying Party to represent the Indemnified Party
and any others the Indemnifying Party may reasonably designate in
connection with such Third Party Claim (in which case the Indemnifying
Party shall not thereafter be responsible for the fees and expenses of
any separate counsel retained by any Indemnified Party except as set
forth below) provided that such counsel is reasonably acceptable to
the Indemnified Party. Notwithstanding an Indemnifying Party's
election to appoint counsel to represent an Indemnified Party in
connection with a Third Party Claim, an Indemnified Party shall have
the right to employ separate counsel, and the Indemnifying Party shall
bear the reasonable fees, costs and expenses of such separate counsel
if (A) the use of counsel selected by the Indemnifying Party to
represent the Indemnified Party would present such counsel with a
conflict of interest or (B) the Indemnifying Party shall not have
employed counsel to represent the Indemnified Party within a
reasonable time after notice of such Third Party Claim. If requested
by the Indemnifying Party, the Indemnified Party agrees to cooperate
with the Indemnifying Party and its counsel in

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<PAGE> 18

contesting any Third Party Claim which the Indemnifying Party defends
or, if appropriate and related to the Third Party Claim in question,
in making any counterclaim against the person asserting the Third
Party Claim, or any cross-complaint against any person. No Third Party
Claim may be settled or compromised by the Indemnified Party without
the prior written consent of the Indemnifying Party, which consent
shall not be unreasonably withheld or delayed or by the Indemnifying
Party without the prior written consent of the Indemnified Party,
which consent shall not be unreasonably withheld or delayed. In the
event the Indemnified Party settles or compromises or consents to the
entry of any judgment with respect to any Third Party Claim without
the prior written consent of the Indemnifying Party, that Indemnified
Party shall be deemed to have waived all rights against the
Indemnifying Party for indemnification under this Section 5.4.

(iii) From and after the delivery of a Claim Notice under this Agreement, at
the reasonable request of the Indemnifying Party, each Indemnified
Party shall grant the Indemnifying Party and its representatives all
reasonable access to the books, records and properties of such
Indemnified Party to the extent reasonably related to the matters to
which the Claim Notice relates. All such access shall be granted
during normal business hours and shall be granted under conditions
that will not unreasonably interfere with the business and operations
of such Indemnified Party. The Indemnifying Party will not, and shall
require that its representatives do not, use (except in connection
with such Claim Notice) or disclose to any third person other than the
Indemnifying Party's representatives (except as may be required by
applicable Law) any information obtained pursuant to this section 5.4
which is designated as confidential by an Indemnified Party.

5.5 FREE WATER IN Y-1 PRODUCT. Buyer shall inspect for the presence of moisture
(free water) in Y-1 Products at the time at which composite samples are taken
pursuant to Section 7.7 and at such other times as Buyer may determine. No
moisture (free water) shall be deemed to be contained within the Y-1 Product
being inspected if no more than one (1) tablespoon of a second phase liquid
comprised of free water, methanol, glycol, amine, or other aqueous solutions is
present within the fluid sample drained from the bottom of the meter strainer
basket located at the Delivery Point. If more than one (1) tablespoon of any
such substances is visibly present in the inspection container, then the NGL's
so delivered shall be deemed to be Off Specification NGL's. The number of
Barrels of NGL's deemed to be Off-Specification NGL's shall be equal to one half
(1/2) of the total number of Barrels delivered, as indicated by flow measurement
readings over the composite sampling measurement period in which the free water
was discovered.

5.6 FREE WATER IN Y-2 PRODUCT. (a) Seller shall filter all Y-2 Product prior to
delivery. A filter equipped with a 60-micron or finer size filtration media
shall be employed. Seller shall employ processing steps in the Panhandle Region
to ensure that any Y-2 Product delivered by Seller to Buyer contains negligible
amounts of free water or aqueous solutions at the temperature and pressure
conditions prevailing at the Delivery Points.

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(b) As soon as practicable following the Effective Date, Buyer shall install at
the Panhandle Region Delivery Points AGAR OW-101 watercut monitoring equipment.
Such equipment shall be initially installed at that Y-2 Product Delivery Point
at which the greatest quantities of Y-2 Product are delivered and sequentially
thereafter at each Delivery Point at which the next greatest quantity is
delivered. The cost for acquisition and installation of the initial equipment
shall be shared equally by the Parties. Subsequent acquisition and installation
costs shall be borne by Buyer. On the last Day of the sixth (6th) full Month
following the installation of the last such meter to be installed at presently
existing Delivery Points, the cumulative weighted average percentage of water in
each Barrel of Y-2 Product delivered at such Delivery Points shall be
determined, and one hundred fifty percent (150%) of such percentage shall
thereafter be the maximum allowable percentage to be utilized for determination
of whether Y-2 Product meets the specification therefor with respect to water;
provided, such percentage shall not be in less than 0.30 liquid volume percent
or greater than 2.0 liquid volume percent. Y-2 Product delivered thereafter
which contains water in excess of the percentage so determined shall be deemed
to be Off-Specification NGL.

(c) During the period beginning on the Effective Date and ending on the last Day
of the sixth (6th) full Month following the installation of the last watercut
monitor (the "Test Period"), Buyer shall deduct from the metered quantity of Y-2
Product delivered hereunder a quantity equal to 0.5 liquid volume percent
thereof. Beginning on the first Day of the Month following the Test Period and
continuing thereafter, Buyer shall deduct from the metered quantity of Y-2
Product delivered hereunder each Month, at each Delivery Point, a quantity equal
to the percentage of water indicated as being present in the Y-2 Product at that
Delivery Point by the water monitoring equipment. Without prejudice to the
provisions of Section 5.2, such monitoring equipment shall in addition be
utilized thereafter for purposes of determining whether Y-2 Product delivered at
such Delivery Point is Off-Specification NGL.

(d) Not later than thirty (30) Days following conclusion of the Test Period, the
Parties shall confer with one another to determine whether the equipment
described in the Section 5.7 is reasonably measuring the quantity of water in
Y-2 Product. If the Parties agree that such measurement is materially
inaccurate, they shall select an alternate methodology for the measurement of
water. In the event the Parties do not agree, the matter may be submitted to an
expert appointed pursuant to Section 9.1(a) within sixty (60) Days thereafter.
The expert shall determine whether the equipment so installed and utilized is
reasonably measuring the water content. In the event, and only in the event,
that the expert determines that the water content is not being reasonably
measured, the expert shall specify alternate equipment to be utilized and
methodologies to be utilized thereafter.

5.7 METHANE IN ETHANE QUALITY INCENTIVE BONUS. (a) If (w) NGL's delivered by
Seller at New Mexico and West Texas Region Delivery Points (other than the
Benedum Plant), as analyzed by Buyer at the Benedum Analyzer, (x) NGL's
delivered by Seller at the Benedum Plant, as analyzed separately by Buyer at the
Benedum Plant, (y) Y-1 Product delivered by Seller at the Dumas and
Sherman-Hansford Plants, as analyzed by Buyer at the Borger fractionator, and
(z) NGL's delivered by Seller at the Giddings Plant, in any Month, in no event
exceed a methane to ethane peak ratio value of 1.75 liquid volume percent (1.75
LV%) at the applicable location, and if the cumulative average of all such
deliveries at the applicable location during the Month

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has a methane to ethane ratio value less than or equal to 1.25 liquid volume
percent (1.25 LV%), then Buyer shall pay to Seller a quality incentive bonus for
deliveries at the applicable locations equal to the product of:

(i) one and one quarter percent (1.25%) of the Barrels of ethane contained
within the NGL's that meet the foregoing qualifications and which are
measured at the applicable location during the Month; and

(ii) the corresponding purchase price per Barrel for ethane determined
pursuant to Article IV, using the price for Linam Ranch Delivery Point
ethane in the case of the West Texas and New Mexico Regions (in the
case of NGL's tested at Benedum), the price for Benedum Plant
deliveries in the case of deliveries at the Benedum Plant, the price
for Panhandle Region Y-1 Product deliveries at the Sherman-Hansford
Delivery Point in the case of deliveries to Borger, and the price for
Giddings Delivery Point ethane in the case of deliveries from the
Giddings Delivery Point.

Provisions regarding the operation of the installation and operation of the
Benedum Analyzer are more specifically set forth in Exhibit E.

(b) It is recognized by the Parties that analysis equipment equivalent to the
Benedum Analyzer will not be installed at Buyer's Borger NGL fractionator prior
to the Effective Date. Such equipment shall be obtained and installed as soon as
reasonably practicable thereafter, and the same shall be operated pursuant to
procedures similar to those utilized with the Benedum Analyzer. Beginning with
the date on which such equipment is installed and ready for use at the Borger
fractionator, whether deliveries of Y-1 Product from the Dumas and
Sherman-Hansford Plants shall receive the incentive bonus described in Section
5.8(a) shall be determined by analysis of the Y-1 Product stream at the Borger
Fractionator. Until such time as such analysis equipment becomes operational,
the peak ratio value requirement that would otherwise apply to such deliveries
shall not apply, and testing of NGL's, for purposes of this Section 5.7, shall
be conducted on the basis of samples taken from the inspection locations at the
Dumas and Sherman-Hansford Plants.

5.8 METHANE IN ETHANE, NON-AFFILIATED NGL PIPELINES. In the event that
operators of pipelines (other than Buyer or its Affiliates) to which NGL is
delivered at Delivery Points other than those described in Section 5.7 consider
methane to be ethane, for volume measurement purposes, if the NGL delivered
meets the specifications in place at such Delivery Point, Buyer will similarly
consider such methane to be ethane for purposes of determining the volume of
ethane delivered and sold hereunder.

ARTICLE VI

SETTLEMENT, INVOICING AND PAYMENT

6.1 INVOICE AND PAYMENT DATES. Promptly, but no later than five (5) Business
Days after the last Day of each Month, Buyer shall submit to Seller a settlement
statement, broken down on

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an NGL Component basis by Delivery Point, for the NGL Component prices and the
gross metered quantity of NGL's delivered by Seller to Buyer hereunder during
the preceding Month. On or after the seventh (7th) Business Day after the last
Day of each Month, Seller shall submit to Buyer an invoice broken down on an NGL
Component basis by Delivery Point, for the quantity and price of NGL's delivered
by Seller and sold to Buyer during the preceding Month, and the best available
estimate of the distribution of ownership of any in-kind NGL's delivered to
Buyer but owned by third parties on a Component basis at each Delivery Point,
together with any corrections of the same for differences between actual
ownership distributions subsequently determined by Seller and prior estimates
previously provided by Seller and recorded by Buyer during the previous Month.
Payment by Buyer to Seller for NGL's sold shall be made on the seventeenth
(17th) Business Day of the Month following the Month of delivery, provided that
Seller's invoice has been timely received. Estimated quantities will be
corrected in the following Month's business. Upon written notice to Seller,
Buyer may withhold from, and offset against, any amounts payable to Seller
hereunder, any amounts payable by Seller to Buyer under this Agreement or under
any other agreement between Buyer and Seller or Seller's Affiliates.

6.2 PAYMENT METHOD; INTEREST RATE. Buyer shall make payment to Seller for NGL
delivered and sold under this Agreement by wire transfer of immediately
available funds to such bank and account as Seller may from time to time
designate by notice to Buyer. Amounts not paid by either Party when due shall
bear interest equal to the Prime Rate plus one percent (1%), or the maximum
lawful rate of interest, whichever is less. For purposes hereof, "Prime Rate"
shall mean that rate published as the consensus Prime Rate by the Wall Street
Journal in its Money Rates Statistics on the date on which payment is due or, in
the event that such rate is not published on the due date, on the next date
thereafter for which it is published.

ARTICLE VII

MEASUREMENT, SAMPLING AND ANALYSIS

7.1 MEASUREMENT, SAMPLING, AND ANALYSIS STANDARDS. Sections 7.2 through 7.17 set
forth the measurement, sampling and analysis standards and procedures applicable
to those Delivery Points at which Buyer or its Affiliates are the owners or
operators. Other Delivery Points are owned or operated by other parties, and
measurement, sampling and analysis standards and procedures associated with such
Delivery Points may differ from the standards and procedures specified in this
Agreement. The Parties nevertheless agree that in each such instance in which
deliveries are to be made at a Delivery Point owned or operated by a third
party, measurement, sampling and analysis performed by such third party shall be
final and binding on the Parties with respect to volumes sold hereunder at such
Delivery Point.

7.2 METERS. The volume and density of NGL's delivered to Buyer by Seller shall
be determined by Buyer or its representative at each Delivery Point using
turbine meter mass measurement facilities of components of standard make
installed, operated and maintained in accordance with the latest edition of
Manual of Petroleum Measurement Standards ("API Manual") and the latest revision
of Gas Processors Association ("GPA") Publication 8182-95.

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<PAGE> 22

7.3 PULSATION. To maintain effective measurement at each Delivery Point, Seller
or its representative shall use reasonable efforts to operate its pumping
facilities to minimize any pulsation effects on the subsequent NGL measurement.

7.4 MINIMUM PRESSURE. Seller shall maintain a minimum pressure at each Delivery
Point equal to twice the pressure drop across the meter at maximum operating
flow rates plus 1.25 times the equilibrium vapor pressure of the NGL product at
the measured temperature at said Delivery Point.

7.5 DELIVERY TICKETS. Buyer or its representative shall record the totalizer
reading daily at a time specified by Buyer or its representative and promptly
inform Seller of this reading when deliveries are being made. Delivery tickets
shall be written at 7:00 a.m. Central Time the first Day of each Month and
whenever the composite sample is removed from the sample container, or as
mutually agreed. Delivery tickets shall be written by Buyer, witnessed by Seller
and copies forwarded immediately to Seller. In the case when mode of operation
changes, such as de-ethanization, Seller will notify Buyer in advance of the
pending change, and Buyer agrees to pull sample and write a meter delivery
ticket representing the period prior to the operation change.

7.6 SAMPLING DEVICES. Buyer or its representative shall furnish or cause to be
furnished an automatic sampling device for obtaining representative samples of
the product delivered hereunder in accordance with the latest revision of GPA
Publication 2174-93. Such sampling device shall be located at each Delivery
Point to extract samples in proportion to the volume of NGL's delivered. The
sampling period for each accounting Month shall extend over the mutually agreed
ticket period and shall be deemed to be representative of the deliveries for the
current accounting Month.

7.7 SAMPLING AND COMPOSITION DETERMINATIONS. The composition of the deliveries
of NGL's from Seller to Buyer hereunder shall be determined in order to
establish the weight percent of the various hydrocarbons contained therein.
Buyer or its representative shall remove composite samples twice each Month,
once on or about the first Day of such Month and once on or about the middle of
such Month, or as otherwise agreed by the Parties. Two (2) separate composite
samples shall be removed from the automatic sampling device in accordance with
the latest revision of GPA Publication 2174-93, one (1) sample for laboratory
analysis, and the second to be retained for referee or joint analysis. Provided
that Seller furnishes to Buyer a sample cylinder during each period, Buyer shall
remove a third composite sample for Seller at each measurement location for
which such sample cylinder is furnished. Buyer will notify Seller five (5) Days
prior to the withdrawing of the NGL samples. Seller or its representative may
witness the withdrawing of the NGL samples. The Buyer's representative sample of
NGL's for each sampling period shall be analyzed by Buyer or its representative
by means of the latest revision of GPA Publication 2177-95, or 2186-95, for
extended analysis of NGL mixtures by gas chromatography. The results of this
analysis of the representative sample shall be forwarded by Buyer to Seller.
Seller may, within twenty (20) Days after receipt of such analysis, challenge
Buyer's analysis by submitting a written objection. If Buyer and Seller cannot
agree on the analysis for that sampling period, then Buyer shall submit the
referee sample to a mutually agreed upon independent laboratory for analysis.
The referee sample analysis results shall be accepted by Buyer and Seller as
final and conclusive. Charges made by such independent

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<PAGE> 23

laboratory shall be borne equally by Buyer and Seller. If Seller does not
challenge the analysis made by Buyer within the twenty (20) Day period following
Seller's receipt of Buyer's analysis, the analysis made by Buyer shall be final
and conclusive. At least every six (6) Months, a sample will be taken for
extended analysis in compliance with the latest revision of GPA Publication
2186-95, to determine the average molecular weight and the weight in pounds per
barrel of the hexane and heavier fractions for use during instances in which GPA
method 2177-95 is used as the analysis method. Such molecular weight and the
weight in pounds per barrel of hexane and heavier fractions shall be used until
the next extended analysis.

7.8 NO SAMPLE. If, for any reason, there is a failure to have a representative
sample for any given period, then an average of the last preceding three
analyses which were acceptable to both Parties during which the Plant was in the
same operating mode shall be substituted for such period unless another method
is agreed upon by both Parties.

7.9 COMPOSITION CALCULATION. The respective quantities of carbon dioxide,
nitrogen, methane, ethane, propane, isobutane, normal butane and pentanes and
heavier hydrocarbons delivered shall be computed by Buyer or its representative
in accordance with the latest revision of GPA Publication 8173-94. The constants
to be used in the calculations to determine the quantities in gallons of the
deliveries shall be those listed in the latest revision of GPA Publication
2145-96.

7.10 MEASUREMENT EQUIPMENT TESTING. All liquid measurement equipment shall be
proved by Buyer or its representative at least once each thirty (30) Days and
prior to any changes in flow rate which may affect metering accuracy after
giving at least five (5) Days notice to Seller as to the date and hour of each
such test. If Seller so desires, it shall be entitled to have representatives
present to witness all provings, but the calibration and repair of the
measurement equipment shall be the responsibility of Buyer or its designee.

7.11 MEASUREMENT EQUIPMENT TOLERANCES AND CORRECTIONS. The average of five (5)
consecutive calibration tests will be taken to obtain the meter correction
factor for the turbine meter if (1) the five calibration tests are within 0.05%
of each other, and (2) the average of the five calibration tests produces a
correction factor within 0.25% of the meter correction factor determined during
the previous period. The average of two (2) consecutive calibration tests will
be used to obtain the density meter correction factor if (1) the two calibration
tests are with 0.05% of each other and (2) the correction factor obtained is
within 0.25% of the density meter correction factor used during the previous
period. Any deviation greater than the above is not acceptable unless otherwise
mutually agreed upon between Buyer and Seller. Buyer or its representative shall
have the responsibility to immediately effect any required equipment
replacement, maintenance or repairs.

7.12 CORRECTION OF PRIOR DELIVERIES. If, upon calibration tests, the turbine
meter or the density meter does not meet with requirements given above, the
factor(s) shall be corrected for a period that shall be agreed upon. In the
event the Parties are not able to reach agreement, the correction shall extend
over one-half (1/2) of the throughput in pounds since the last calibration of
the equipment.

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<PAGE> 24

7.13 SPECIAL CALIBRATION TESTS. Either Party may request special calibration
tests of the measurement facilities in addition to the regular Monthly tests.
The expense of such special test shall be borne by the Party requesting same,
unless such test shows that the measurement facilities are in error by more than
one-half percent (0.5%) by "mass" measurement, in which case the expense of the
special test shall be borne by Buyer.

7.14 CORRECTION OF MASS MEASUREMENT ERRORS. If any special test shows that the
measurement facilities are in error one-half percent (0.5%) or less by "mass"
measurement, previous calibration factors of such equipment shall be considered
as correct. However, the measurement facilities shall be properly adjusted at
once to record accurately. If any special test shows that the measurement
facilities are in error by more than one-half percent (0.5%) by "mass"
measurement, the equipment shall be properly calibrated at once to record
accurately and the previous "mass" readings of such equipment shall be corrected
to zero error for any period which is known or agreed upon. In case said period
is not known or agreed upon, such correction shall be for one-half of the
throughput in pounds since the last calibration of the equipment.

7.15 OUT OF SERVICE CORRECTIONS. The computed NGL Component volumes delivered
during any period the measurement system is out of service or in need of repair
shall be estimated by Buyer or its representative by one of the following
methods, in the order stated:

(i) by using the data recorded by any check measuring equipment installed
and accurately registering;

(ii) by correcting the error if the percentage of error is ascertained by
calibration, test, or mathematical calculation; or

(iii) by comparison with deliveries during a period under similar conditions
when the measurement system was registering accurately.

7.16 SELLER ACCESS. Seller shall be provided measurement information, including
access to Buyer's measuring facilities' data transmission signal.

7.17 NOTIFICATION OF OPERATIONAL CONDITIONS. Seller shall promptly notify Buyer
of any operational conditions that may affect NGL specifications. Seller shall
use its best reasonable efforts to remedy any such specification problems.

ARTICLE VIII

CUSTODY, TITLE AND RISK OF LOSS

8.1 TITLE PASSAGE. Custody, title and risk of loss to the NGL's delivered by
Seller to Buyer under this Agreement shall pass from Seller to Buyer at the
Delivery Points.

8.2 WARRANTY OF TITLE. Seller hereby warrants that it has title to the NGL's
sold by it hereunder and the right to sell the same, and warrants that all such
NGL's are owned by Seller

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free and clear from all liens, encumbrances and adverse claims. Seller will
defend, indemnify, and save Buyer, its affiliates, and their officers, agents,
and employees harmless from all suits, claims, liens, damages, costs (including
attorneys' fees and costs of litigation), losses, expenses, and encumbrances of
whatsoever nature arising from and out of claims of any or all persons of and
concerning title to NGL's delivered to Buyer and claims for royalties, taxes,
license fees, payments and other charges thereon applicable before the title
transfers to Buyer.

ARTICLE IX

DISPUTE RESOLUTION

9.1 NEGOTIATIONS/EXPERT REFERRAL FOR CERTAIN DISPUTES. (a) This Section 9.1
shall apply with respect to those matters referred to in Section 3.5(c), 4.5,
4.6, 5.6 and Exhibit E on which the Parties are required to reach agreement, and
those matters described in Article VII. In order to come to agreement on any
issue arising under or relating to those provisions, either Party may make a
written request to the other requesting a meeting of the Parties' respective
Senior Management with respect to Sections 4.5 and 4.6 and operational managers
with respect to Article VII for the purpose of discussing and resolving the
same. Such Senior Management or operational managers shall meet within five (5)
Business Days thereafter by teleconference or at a location selected by the
requesting Party and reasonably convenient for both Buyer and Seller. If such
meeting fails to result in an agreement within seven (7) Days thereafter, either
Party (the "Initiating Party") may request in writing that the matter be
referred to an expert.

(b) An expert is a person generally recognized as an expert in the field or
fields of expertise relevant to the issue on which the Parties are required to
come to agreement. Without the specific agreement of both Parties, no person
shall serve as an expert who has ever been previously employed or hired as a
consultant for either of the Parties. In the event that the Parties cannot agree
on the expert within seven (7) Days after the Initiating Party's request for
referral, then either Party may obtain a designation of an expert pursuant to
the following procedure. The Center for Public Resources Institute for Dispute
Resolution (the "Institute") shall be requested by the Initiating Party to
provide the names of seven individuals who are experts in the relevant field. No
expert shall be a current or former director, officer or employee of either
Party or its Affiliates; an attorney (or member of a law firm) who has rendered
legal services to either Party or its Affiliates within the preceding three
Years; or an owner of any of the common stock of either Party, or its
Affiliates. The Parties shall alternate the striking of single names from the
list of experts (with the Initiating Party striking the first name) until only
one (1) expert remains on the list, and such expert shall resolve the matter at
issue. Each Party shall have one (1) Business Day to strike a name, with the
first name to be struck on the seventh (7th) Day following the date on which the
list shall have been received by both Parties. If a Party does not strike a name
within such one (1) Day period such Party's right to strike a name on such Day
shall be forfeited. If the expert selected by this process cannot serve for any
reason, then the person whose name was the last name stricken by the Parties
from the list of experts shall be selected as the arbitrator instead. If that
person cannot serve for any reason then the Parties will obtain a new list of
arbitrators from the Institute and will repeat the striking process set forth
herein.

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(c) Once designated, the expert will consult with both Parties (provided there
shall be no ex parte communications) and review all relevant material submitted
by each Party (with any information provided to the expert also to be provided
to the other Party). Oral submissions to the expert may be made by
representatives of both Parties as long as both Parties are present at the time
of such oral submissions, and such submissions shall be completed within sixty
(60) Days following selection of the expert. Subject to the prior written
approval of Buyer and Seller, the expert may obtain independent or technical
advice as he or she may deem necessary. Following consideration of the
submissions of the Parties, the expert shall issue his decision, including a
written statement of findings and reasons, and the same shall thereupon
constitute the agreement of the Parties regarding that matter. Except with
respect to determinations under Section 4.5, the Parties waive any right of
appeal which they may have either with respect to the selection the expert and
the findings and determinations of the expert. Either Party, if dissatisfied
with a determination under Section 4.5, may appeal the same by arbitration under
Section 9.2.

(d) Each Party shall bear its respective costs, and the Parties shall share
equally the cost of the expert and any independent advisers consulted by the
expert.

9.2 NEGOTIATIONS/BINDING ARBITRATION OF OTHER DISPUTES. Except with respect to
the matters described in Section 9.1(a), any dispute, controversy or claim
arising out of or relating to this Agreement, or the breach or performance
hereof, including, but not limited to, any disputes concerning the
interpretation of the terms and provisions hereof, shall be resolved through the
use of the following procedures:

(a) The Parties will initially attempt in good faith to resolve any
disputes, controversy or claim arising out of or relating to this
Agreement.

(b) Should the Parties directly involved in any dispute, controversy or
claim be unable to resolve same within a reasonable period of time,
such dispute, controversy or claim shall be submitted to the Senior
Management with such explanation or documentation as the Parties deem
appropriate to aid the Senior Management in their consideration of the
issues presented. The date the matter is first submitted to the Senior
Management shall be referred to as the "Submission Date." The Senior
Management shall attempt in good faith, through the process of
discussion and negotiation, to resolve any dispute, controversy, or
claim presented to it within forty-five (45) Days after the Submission
Date.

(c) If the Senior Management cannot so resolve any dispute, controversy,
or claim submitted to it within forty-five (45) Days after the
Submission Date, either Party may request that the matter be resolved
through arbitration by submitting a written notice (the "Arbitration
Notice") to the other. Any arbitration that is conducted hereunder
shall be governed by the Federal Arbitration Act, 9 U.S.C. Sections
1-16, et seq., and will not be governed by the arbitration acts,
statutes or rules of any other jurisdiction.

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(d) The Arbitration Notice shall name the noticing Party's arbitrator and
shall contain a statement of the issue(s) presented for arbitration.
Within fifteen (15) Days of receipt of an Arbitration Notice, the
other Party shall name its arbitrator by written notice to the other
Party and may designate any additional issue(s) for arbitration. The
two named arbitrators shall select the third arbitrator within fifteen
(15) Days after the date on which the second arbitrator was named.
Should the two arbitrators fail to agree on the selection of the third
arbitrator, either Party shall be entitled to request the Senior Judge
of the United States District Court for the Southern District of Texas
to select the third arbitrator. All arbitrators shall be qualified by
education or experience within the natural gas or natural gas liquids
industry to decide the issues presented for arbitration. No arbitrator
shall be: a current or former director, officer or employee of either
Party or its Affiliates; an attorney (or member of a law firm) who has
rendered legal services to either Party or its Affiliates within the
preceding three Years; or an owner of any of the common stock of
either Party, or its Affiliates.

(e) The three arbitrators shall commence the arbitration proceedings
within twenty-five (25) Days following the appointment of the third
arbitrator. The arbitration proceedings shall be held in Dallas,
Texas. The arbitrators shall have the authority to establish rules and
procedures governing the arbitration proceedings. Each Party shall
have the opportunity to present its evidence at the hearing. The
arbitrators may call for the submission of pre-hearing statements of
position and legal authority. The arbitrators' decision must be
rendered within thirty (30) Days following the conclusion of the
hearing or submission of evidence, but no later than ninety (90) Days
after appointment of the third arbitrator.

(f) The decision of the arbitrators, or a majority of them, shall be in
writing, shall include a statement of findings and reasons, and shall
be final and binding upon the Parties as to the issue(s) submitted.
The cost of the hearing shall be shared equally by the Parties, and
each Party shall be responsible for its own expenses and those of its
counsel or other representatives. Each Party hereby irrevocably
waives, to the fullest extent permitted by law, any objection it may
have to the arbitrability of any such disputes, controversies or
claims and further agrees that a final determination in any such
arbitration proceeding shall be conclusive and binding upon each
Party. Judgment on the award rendered by the arbitrator may be entered
in any court having jurisdiction thereof. The prevailing Party shall
be entitled to recover reasonable attorneys' fees and court costs in
any court proceeding relating to the enforcement or collection of any
award or judgment rendered by the arbitration panel under this
Agreement.

(g) All deadlines specified herein may be extended by mutual written
agreement of the Parties. The procedures specified herein shall be the
sole and exclusive procedures for the resolution of disputes between
the Parties arising out of or relating to this Agreement; provided,
however, that a Party may seek a preliminary injunction or other
preliminary judicial relief if in its judgment such action is
necessary to avoid irreparable damage. Despite such action, the
Parties

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will continue to participate in good faith in the procedures specified
herein. All applicable statutes of limitation, including, without
limitation, contractual limitation periods provided for in this
Agreement, shall be tolled while the procedures specified in this
Section are pending. The Parties will take all actions, if any,
necessary to effectuate the tolling of any applicable statutes of
limitation.

9.3 CONTINUED PERFORMANCE. While any matter under dispute is being resolved
pursuant to the provisions of this Article IX, the Parties shall continue to
perform their obligations hereunder.

ARTICLE X

FORCE MAJEURE

10.1 SUSPENSION OF PERFORMANCE. In the event either Party is rendered unable,
wholly or in part, by Force Majeure to carry out its obligations under this
Agreement, other than to make payments of money when due, such Party shall give
notice and full particulars of such Force Majeure event to the other Party as
soon as reasonably possible after the occurrence of the cause relied on, and the
obligations of the Parties, so far as they are affected by such Force Majeure,
shall be suspended during the continuance of any inability so caused but for no
longer period, and such cause shall as far as possible be remedied with all
reasonable dispatch. The Party giving notice shall cooperate in assisting the
other Party to maintain its operations and throughput including access to owned,
affiliated, and third Party systems.

10.2 FORCE MAJEURE DEFINITION. The term "Force Majeure," as employed herein,
shall mean an act of God; strike, lockout or other industrial disturbance; act
of the public enemy; war; blockade; riot; lightning; fire; storm, flood;
explosion; malfunction or a necessity for making repairs to lines of pipe,
pumps, compressors, valves, gauges, or any equipment used thereon; action, order
or regulation by any government or governmental agency which prevents in whole
or in part performance hereunder; and any other sudden, accidental and
unanticipated event, matter or cause, whether or not of the same class or kind
as set forth above, which is not within the control of the Party affected
thereby, and the effects of which cannot be overcome by the exercise of due
diligence.

10.3 LABOR MATTERS EXCEPTION. The settlement of strikes or lockouts shall be
entirely within the discretion of the Party having the difficulty, and the above
requirement that any Force Majeure shall be remedied with all reasonable
dispatch shall not require the settlement of strikes or lockouts by acceding to
the demands of the opposing Party when such course is inadvisable in the
discretion of the Party having the difficulty.

10.4 INTERIM ACTIONS. During the period for which either Party is prevented,
either in whole or in part, by reason of Force Majeure, from performing its
obligations under this Agreement, the other Party may make such reasonable and
temporary, alternative arrangements for the delivery or receipt of NGL to the
extent affected by such Force Majeure (or, in the case of Buyer, the acquisition
of the same from third parties). Upon the termination or cessation of such

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circumstances, the Parties shall resume the performance of their obligations
hereunder (subject to the fulfillment of any remaining obligations under such
reasonable and temporary, alternative arrangements made as a result of such
Force Majeure.

ARTICLE XI

TAXES

11.1 SELLER TAXES. Seller shall pay all taxes, fees or other similar levies
(except sales and use taxes, or any taxes equivalent thereto and imposed in lieu
thereof, all such excluded taxes being referred to as "Sales & Use Taxes") which
may be assessed or otherwise applicable to the NGL's delivered to Buyer
hereunder prior to delivery to Buyer, and, in the event the Buyer is required by
law to pay any of said taxes, fees or other similar levies, Seller shall
reimburse Buyer for such payments.

11.2 BUYER TAXES. Buyer shall pay all taxes, fees or other similar levies which
may be assessed or otherwise applicable to the NGL's delivered to Buyer
hereunder at and after delivery to Buyer, and, in the event Seller is required
by law to pay any of said taxes, fees or other similar levies, Buyer shall
reimburse Seller for such payment.

11.3 EXEMPTION CERTIFICATES. Buyer shall provide Seller with an exemption
certificate(s), if any, in a form acceptable to the appropriate taxing authority
for sales of NGL under this Agreement, and shall be responsible for the payment
of Sales and Use Taxes for sales of NGL hereunder if it fails to do so, or if
such taxes are otherwise assessed on such sales.

11.4 INCOME TAXES. Neither Party shall be responsible for any taxes of the other
Party measured by the income of such Party.

ARTICLE XII

NOTICES

12.1 ADDRESSES. All notices or communications between the Parties required or
allowed under this Agreement shall be in writing and shall be sent by certified
United States mail (Return Receipt Requested) or first class United States mail,
in each case with postage prepaid, by a facsimile transmission with receipt
confirmed, or by overnight courier, addressed as follows:

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IF TO Buyer:

PHILLIPS 66 COMPANY
Attn: Manager of Natural Gas Liquids
788-B Adams Building
Bartlesville, Oklahoma 74004
Fax Number: (918) 662-2178

IF TO Seller:

Correspondence:

GPM Gas Corporation
Attn: Gas Marketing
1300 Post Oak Blvd., Suite 800
Houston, TX 77056

Fax Number: (713) 297-5964

Payments:

Chase Manhattan Bank
New York, New York
ABA No. 021000021,
For credit to GPM Gas Corporation,
Account 144-033-880

12.2 TIME OF NOTICE. Any notice or communication shall be deemed to have been
properly given when received. Any notice or communication successfully
transmitted by facsimile after 5:00 p.m. on a given Business Day, as evidenced
by automatic confirmation produced by the sender's transmission equipment, shall
be deemed received on the next succeeding Business Day.

12.3 CHANGE OF ADDRESS. Either Party may change its notice address by giving
notice to the other Party in the manner set forth hereinabove; provided,
however, that no change of address notice shall be effective until received by
the other Party. Each Party shall provide the other with all names, telephone
and facsimile numbers necessary for its performance under this Agreement.

ARTICLE XIII

RECORDS AND AUDIT

13.1 Buyer and Seller shall maintain true and correct sets of records pertaining
to performance of this Agreement and all transactions related thereto, and agree
to retain all such records for a

-28-

<PAGE> 31

period of not less than two (2) years following the end of the production Month.
Any representative or representatives authorized by either Party may audit any
and all such records of the other Party at any reasonable time or times during
performance of this Agreement and during the two-year period after completion of
performance, for purposes of determining compliance with the terms hereof and to
verify that no illegal or unauthorized payments or rebates have been paid to or
by an employee or agent of either Party hereto.

ARTICLE XIV

CONFIDENTIALITY

14.1 CONFIDENTIAL MATTERS. The terms of this Agreement, including, but not
limited to the price paid for NGL's, the quantities of NGL's purchased or sold
and all other terms of this Agreement shall be kept confidential by the Parties
hereto, except (i) as provided in Section 14.2, (ii) to the extent such
information must be disclosed for the purpose of effectuating transportation of
NGL's, (iii) as may be required to be disclosed by order of any court or other
governmental authority (a "Compelled Disclosure"), (iv) for disclosure to
Seller's or Buyer's respective attorneys and consultants or to any lenders and
their attorneys or consultants in connection with any equity and debt financing
of Seller or Buyer, or (v) as required in connection with Seller's or Buyer's
risk management activity. Before any disclosure of the terms of this Agreement
(other than a Compelled Disclosure), the Party disclosing the terms shall
require that the third Party receiving the information execute a confidentiality
statement containing terms substantially the same as those in this Article XIV.
If either Party or any of its officers, directors, employees, agents or advisors
become required to disclose any terms of this Agreement to third Parties
pursuant to a Compelled Disclosure, the disclosing Party will give the other
Party prompt notice of that fact, shall furnish only that portion of the
Agreement which it is legally required to furnish, and shall exercise all
reasonable efforts to obtain assurance that confidential treatment will be
accorded such information by appropriate protective order or otherwise.

14.2 NOTICE. In the event that interrogatories, requests for production of
documents, document subpoenas, civil investigative demands or similar processes
call for Seller or Buyer, in the opinion of counsel, to disclose any
confidential information in connection with this Agreement, it is agreed that
the Party from whom such disclosure is sought will provide the other Party with
prompt notice of such process so that the other Party may seek an appropriate
protective order. The Party seeking the protective order agrees to keep the
other Party informed of the progress on and the terms of any such protective
order. In the event such protective order is not obtained, the Party from whom
such disclosure is sought shall not be liable for complying with such legal
process.

-29-

<PAGE> 32

ARTICLE XV

MISCELLANEOUS PROVISIONS

15.1 PARTIAL INVALIDITY. If any provision hereof is found by final and
unappealable order or award to be non-enforceable, for any reason whatsoever, it
shall be adjusted rather than voided, if possible, in order to achieve the
intent of the Parties. In any event, all other provisions of this Agreement
shall be deemed valid, binding and enforceable to the full extent allowed by
law.

15.2 DEFAULT AND NONWAIVER. The failure of either Party to enforce any of the
provisions of this Agreement at any time shall not be construed to be a waiver
of such provision unless so notified by such Party in writing. No waiver of any
breach of this Agreement shall be held to be a waiver of any other breach.

15.3 ENTIRE AGREEMENT. This Agreement contains the entire and only agreement
between the Parties concerning the subject matter hereof, and it supersedes any
prior correspondence, communications, agreements and understandings, whether
oral or written, between the Parties. In order to be binding upon Buyer or
Seller, any modification or amendment to this Agreement, or of any of the
provisions hereof, must be in writing signed by both Parties. As of the
Effective Date, this Agreement supersedes and replaces that certain Natural Gas
Liquids Output Purchase and Sale Agreement, as amended, that was effective as of
January 1, 1992.

15.4 ASSIGNMENT, SUCCESSORS. The terms, conditions and provisions of this
Agreement shall inure to the benefit of the Parties hereto and their respective
successors and assigns. Neither Party shall assign this Agreement, in whole or
in part, without the other Party's prior written consent except to an Affiliate.
Notwithstanding the foregoing, however, either Party may assign all or any part
of its rights and obligations hereunder (and cause a novation of this Agreement
to occur with respect to the rights and obligations so assigned) incident to a
sale, transfer, amalgamation, joint venture or other restructuring involving all
or a material portion of its assets related, in the case of Buyer, to its
petrochemical production activities or its refining, marketing and
transportation activities, or, in the case of Seller, to its NGL production
activities, provided that (i) the transferee or other successor entity resulting
from such transaction agrees to assume the assigning Party's rights and
obligations hereunder (and to become a party hereto pursuant to a novation of
this Agreement with respect to the rights and obligations so assigned) as of the
effective date of any such transaction, and (ii) the assignee has a rating on
its senior, secured debt that is not below investment grade (currently BBB- as
measured by Standard & Poor's Corporation). In the event that the assignee does
not have such rating, such assignment may nevertheless be made provided that, in
the case of an assignment by Seller, performance of the assignee's obligations
is guaranteed by Seller and, in the case of an assignment by Buyer, such
performance is guaranteed by Buyer. Any such guarantees shall extend to the
matters described in the form of the guarantee attached hereto as Exhibit F, and
shall remain in effect until such time, if any, as the assignee achieves an
investment grade rating for its senior secured debt. For greater certainty,
either Party's right to assign may be exercised with respect to all Regions, or
with respect to any specified Region or Regions.

-30-

<PAGE> 33

15.5 LAWS AND REGULATIONS. This Agreement is in all respects subject to all
Federal, State and local laws and all directives, regulations and orders issued
or published by any Federal, State or local board, commission, or agency

15.6 GOVERNING LAW. REGARDLESS OF THE PLACE OF CONTRACTING, PLACE(S) OF
PERFORMANCE, OR OTHERWISE, THIS AGREEMENT, AND ALL AMENDMENTS, MODIFICATIONS,
ALTERATIONS OR SUPPLEMENTS THERETO, IF ANY, AND ALL QUESTIONS AS TO THE NATURE,
VALIDITY AND INTERPRETATION OF ANY OF THE FOREGOING SHALL BE GOVERNED BY THE
LAWS OF THE STATE OF TEXAS WITHOUT REFERENCE TO PRINCIPLES OF CONFLICTS OF LAWS.

15.7 HEADINGS. The Article and Section headings of this Agreement have been
inserted only to facilitate reference and shall have no bearing on the
construction and interpretation of this Agreement

15.8 NO THIRD PARTY BENEFICIARIES. This Agreement is entered into for the
benefit of the Parties, their successors and permitted assigns, and nothing in
this Agreement shall be construed as creating any rights or benefits in or to
any third Party.

15.9 SURVIVAL. Any provision of this Agreement that expressly or by implication
comes into or remains in force following the termination or expiration of this
Agreement shall survive the termination or expiration of this Agreement as set
forth in such provisions.

15.10 COUNTERPARTS. This Agreement may be executed in one or more counterparts,
each of which shall be deemed an original, but all of which together shall
constitute one and the same instrument.

IN WITNESS WHEREOF, the Parties have set their hands by their duly
authorized officials as of the date set forth above.

PHILLIPS 66 COMPANY, a division of GPM GAS CORPORATION
PHILLIPS PETROLEUM COMPANY

By: /s/ B.Z. PARKER By: /s/ M.J. PANATIER
------------------------------- --------------------------------
Title: Executive Vice President Title: President
---------------------------- -----------------------------

Executed on: December 1, 1999 Executed on: December 2, 1999
---------------------- -----------------------

-31-

<PAGE> 34

EXHIBIT A
DELIVERY POINT

<TABLE>
<CAPTION>
CONTRACT METER ID MAXIMUM APPROXIMATE
DELIVERY POINT REGION LOCATION NO. OPERATOR OPERATING NGL HISTORIC
PRESSURE GRADE QUANTITY SOLD
(PSIG) (BPD)
(See Note 1)
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Sherman-Hansford Plant Panhandle Hansford Co., TX 9614 Buyer 1,440 Y-1 13,100
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Dumas Plant Panhandle Moore Co., TX 9617 Buyer 1,125 Y-1 6,400
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Rock Creek Plant Panhandle Hutchinson Co., TX 9619 Buyer 1,430 Y-1 15,600
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Region Total Y-1 Panhandle Various Various Various Various Y-1 35,100
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Sherman-Hansford Plant Panhandle Hansford Co., TX 9875 Buyer 750 Y-2 1,200
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Dumas Plant Panhandle Moore Co., TX 9946 Buyer 1,115 Y-2 600
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Sneed Station/Treater Panhandle Moore Co., TX 9957 Buyer 1,180 Y-2 1,100
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Rock Creek Plant Panhandle Hutchinson Co., TX 9959 Buyer 570 Y-2 1,600
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Gray Booster Panhandle Gray Co., TX 9855 Buyer 1,395 Y-2 1,500
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Region Total Y-2 Panhandle Various Various Various Various Y-2 6,000
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Okarche Plant Oklahoma Kingfisher Co., OK 9510 Other 1,320 Y-1 10,700
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Kingfisher Plant Oklahoma Kingfisher Co., OK 9530 Other 1,320 Y-1 9,400
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Mooreland to Koch Oklahoma Woodward Co., OK Koch Other Per Koch Y-1 6,000
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Cimarron Plant Oklahoma Woodward Co., OK Koch Other Per Koch Y-1 500
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Binger Plant Oklahoma Caddo Co., OK Koch Other Per Koch Y-1 200
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Region Total Oklahoma Various Various Various Various Y-1 26,800
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Artesia Plant New Mexico Eddy Co., NM 9839 Buyer 1,045 Y-1 4,200
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Eunice Plant New Mexico Lea Co., NM 9883 Buyer 1,045 Y-1 8,900
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Eunice to WTPL New Mexico Lea Co., NM WTPL Other Per WTPL Y-1 Included above
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Linam Ranch New Mexico Lea Co., NM 9626 Buyer 1,045 Y-1 12,900
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Linam Ranch to Koch New Mexico Lea Co., NM Koch Other Per Koch Y-1 Included above
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Linam Ranch to WTPL New Mexico Lea Co., NM WTPL Other Per WTPL Y-1 Included above
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Region Total New Mexico Various Various Various Various Y-1 26,000
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Fullerton Plant West Texas Andrews Co., TX 9829 Buyer 1,045 Y-1 10,200
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Fullerton to WTPL West Texas Andrews Co., TX WTPL Other Per WTPL Y-1 Included above
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Goldsmith Plant West Texas Ector Co., TX 9943 Buyer 1,100 Y-1 17,300
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Goldsmith to Koch West Texas Ector Co., TX Koch Other Per Koch Y-1 Included above
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Spraberry Plant West Texas Midland Co., TX 9546 Buyer 1,100 Y-1 7,400
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Benedum Plant West Texas Upton Co., TX 9906 Buyer 1,125 Y-1 5,300
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Region Total West Texas Various Various Various Various Y-1 40,200
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------

- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Giddings Plant Austin Bastrop Co., TX 9918 Buyer 1,335 Y-1 8,000
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------

- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
Combined Total All Regions Various Various Various Various Y-1/Y-2 142,100
- ----------------------- ----------------- ----------------------- ---------- ---------- -------------- --------- ------------------
</TABLE>

(1) Buyer reserves the right to modify the maximum operating pressure at each
Delivery Point. Buyer shall provide to Seller reasonable notice of any such
modifications.

<PAGE> 35

EXHIBIT B-1
NGL/Y-1 PRODUCTS QUALITY SPECIFICATIONS
SCOPE AND APPLICATION

<TABLE>
<CAPTION>
NGL CHARACTERISTICS MINIMUM MAXIMUM TEST METHOD
==================================================== ========== ============ ====================
<S> <C> <C>
1. COMPOSITION (LV%)
- ---------------------------------------------------- ---------- ------------ --------------------
Carbon Dioxide, LV% of ethane volume: (Note 1) 0.35 GPA 2186
- ---------------------------------------------------- ---------- ------------ --------------------
Methane, LV% of total volume, or 0.50 GPA 2186
- ---------------------------------------------------- ---------- ------------ --------------------
LV% of ethane volume, if greater: (Note 1) 1.50 GPA 2186
- ---------------------------------------------------- ---------- ------------ --------------------
Ethane: N/A GPA 2186
- ---------------------------------------------------- ---------- ------------ --------------------
Aromatics: 10.0 GPA 2186
- ---------------------------------------------------- ---------- ------------ --------------------
Olefins: 1.0 GPA 2186
- ---------------------------------------------------- ---------- ------------ --------------------
2. VAPOR PRESSURE, psig @100(0)F: 600 ASTM D-1267
- ---------------------------------------------------- ---------- ------------ --------------------
3. CORROSION, copper strip @100(0)F: No.1 ASTM D-1838
- ---------------------------------------------------- ---------- ------------ --------------------
4. TOTAL SULFUR, ppmw: 1,200 ASTM D-2784
- ---------------------------------------------------- ---------- ------------ --------------------
5. HYDROGEN SULFIDE: Pass -- ASTM D-2420
- ---------------------------------------------------- ---------- ------------ --------------------
6. RESIDUAL MATTER,
- ---------------------------------------------------- ---------- ------------ --------------------
Oil stain observation: Pass -- ASTM D-2158
- ---------------------------------------------------- ---------- ------------ --------------------
7. DISTILLATION, End point,(0)F: 375 ASTM D-2887
- ---------------------------------------------------- ---------- ------------ --------------------
8. COLOR, Saybolt No.: +25 -- ASTM D-156(Note 2)
- ---------------------------------------------------- ---------- ------------ --------------------
or, by colorimeter method, %: (Note 4) 100 -- NGL-96-02-R1
- ---------------------------------------------------- ---------- ------------ --------------------
9. MOISTURE CONTENT,
- ---------------------------------------------------- ---------- ------------ --------------------
free water at delivery conditions: -- (Note 5) NGL-96-01-R1
- ---------------------------------------------------- ---------- ------------ --------------------
10. TEMPERATURE, degrees F:
Ethane (mu) 50 mole % 40 90 Inspection
Ethane < 50 mole % 40 110
- ---------------------------------------------------- ---------- ------------ --------------------
11. OTHER DELETERIOUS SUBSTANCES: See note 3 NGL-96-01-R1
==================================================== ========== ============ ====================
</TABLE>

NOTES:

(1) Methane, carbon dioxide and water shall have no value.

(2) Test modified by first weathering sample to ambient temperature and pressure
conditions.

(3) The product shall contain no substances which may reasonably have a
deleterious effect upon the operation of the pipelines and NGL processing
facilities, or upon the fractionated products derived therefrom.

(4) 100% specification is for a colorimeter calibrated such that distilled water
reference standard reads 100% on 0-200% digital instrument scale, or the
specification shall be 80% for a colorimeter calibrated such that distilled
water reads 80% on 0-100% analog instrument scale.

(5) See Section 5.6 on determination of free water.

<PAGE> 36

EXHIBIT B-2
Y-2 PRODUCTS QUALITY SPECIFICATIONS
SCOPE AND APPLICATION

<TABLE>
<CAPTION>
NGL CHARACTERISTICS RESULT TEST METHOD
LATEST REVISION
============================================== ======================= ===================
<S> <C> <C>
NGL CHARACTERISTICS - FIELD TESTS
- ---------------------------------------------- ----------------------- -------------------
Visual inspection,
- ---------------------------------------------- ----------------------- -------------------
Suspended solids / particulate matter: None NGL-96-01-R1
- ---------------------------------------------- ----------------------- -------------------
Deleterious substances (Note 4): None NGL-96-01-R1
- ---------------------------------------------- ----------------------- -------------------
Color, by colorimeter method, % (Note 6) 25 min. NGL-96-02-R1
- ---------------------------------------------- ----------------------- -------------------
NGL temperature, deg F: 40 min. / 100 max. Inspection
- ---------------------------------------------- ----------------------- -------------------

- ---------------------------------------------- ----------------------- -------------------
NGL CHARACTERISTICS - LAB TESTS
- ---------------------------------------------- ----------------------- -------------------
Compositional Analysis, LV%
- ---------------------------------------------- ----------------------- -------------------
Methane (Note 1): 0.50 max. GPA 2186
- ---------------------------------------------- ----------------------- -------------------
Methane plus ethane (Note 1): 2.00 max. GPA 2186
- ---------------------------------------------- ----------------------- -------------------
Carbon dioxide (Note 1): 0.10 max. GPA 2186
- ---------------------------------------------- ----------------------- -------------------
Olefins: 0.20 max. GPA 2186
- ---------------------------------------------- ----------------------- -------------------
Water (Note 1): Report (Note 5)
- ---------------------------------------------- ----------------------- -------------------
Calculated Parameters (Note 2),
- ---------------------------------------------- ----------------------- -------------------
Vapor pressure, psia @ 100 F: 100 max. GPA 2186
- ---------------------------------------------- ----------------------- -------------------
Average molecular weight of C6+: 110 max. GPA 2186
- ---------------------------------------------- ----------------------- -------------------
Total sulfur, ppmw: 1,200 max. ASTM D-2784
- ---------------------------------------------- ----------------------- -------------------

- ---------------------------------------------- ----------------------- -------------------
Total fluorides, ppmw: 10 max UOP-619
- ---------------------------------------------- ----------------------- -------------------
Volatile fluorides, ppmw (Note 3): 0.10 max. UOP-619
- ---------------------------------------------- ----------------------- -------------------
Non-volatile matter, ppmw 1,000 max. PPCO SLP-1629
- ---------------------------------------------- ----------------------- -------------------
Distillation end point, deg F: 375 F max. ASTM D-2887
============================================== ======================= ===================
</TABLE>

NOTES: (1) Water, methane, and carbon dioxide shall have no value.

(2) Vapor pressure and average molecular weight parameters are
determined by calculations based upon GLC compositional analysis of
sample.

(3) Fluoride compounds present in portion of Product sample with
boiling points of less than 100 deg F are limited to 0.10 ppmw
maximum.

(4) All products shall contain no substances which may reasonably have
a deleterious effect upon the operation of the pipeline and NGL
processing facilities, or upon the fractionated products derived
therefrom.

(5) See Section 5.7 regarding determination of water in Y-2 product.

(6) 25% specification is for a digital colorimeter calibrated such that
the distilled water reference standard reads 100% on a 0200%
digital instrument scale. Product sample shall be weathered to
ambient temperature and pressure conditions prior to test.

<PAGE> 37

EXHIBIT C
REFERENCE PRICES

<TABLE>
<CAPTION>
Y-1 NGL Component Oklahoma Panhandle West Texas, Austin and New Mexico
- ----------------- --------------- ----------------------------- ---------------------------------

<S> <C> <C> <C>
OPIS Conway/ OPIS MONT Belvieu OPIS Belvieu
Ethane Group 140 EP Mix 50% as EP Mix
Ethane MAPCO 50% as Purity Ethane

OPIS Conway/ 28.2% of Ethane
Group 140 as OPIS Belvieu Propane, TET, OPIS Belvieu
Propane Propane MAPCO and remainder as OPIS Conway/ TET Propane
Group 140 Propane (See Note)

OPIS Conway/ OPIS Conway/
i-Butane Group 140 Group 140 OPIS Belvieu
Isobutane MAPCO Isobutane MAPCO Non-TET Isobutane

n-Butane OPIS Conway/ OPIS Conway/ OPIS Belvieu
Group 140 Group 140
N. Butane MAPCO N. Butane MAPCO Non-TET n-Butane

Pentanes Plus OPIS Conway/ OPIS Conway/
Group 140 Group 140 OPIS Belvieu
N. Gas MAPCO N. Gas MAPCO Non-TET N. Gas

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

<CAPTION>
Y-2 NGL Component Oklahoma Panhandle West Texas, Austin and New Mexico
- ----------------- --------------- ----------------------------- ---------------------------------

<S> <C> <C> <C>
OPIS Conway/
Ethane -- Group 140 --
Ethane MAPCO

Propane OPIS Conway/
-- Group 140 --
Propane MAPCO

i-Butane OPIS Conway/
-- Group 140 --
Isobutane

n-Butane OPIS Conway/
-- Group 140 --
N. Butane MAPCO

Pentanes Plus -- WTI Crude Oil --
NYMEX Daily Close
- ----------------- --------------- ----------------------------- ---------------------------------
</TABLE>

<PAGE> 38

Note:. In the Panhandle Region, a portion of the propane contained in Y-1
product, if any, up to 28.2% of the relative amount of ethane present, will be
valued as OPIS Mt. Belvieu price and the remainder as Conway propane. An example
of the determination of such quantity is as follows:

<TABLE>
<CAPTION>
NGL Components Barrels
<S> <C>
Methane 1,250
Ethane 97,150 x 0.282 = 27,396.3
Propane 101,100
i-Butane 20,100
n-Butane 47,700
Pentanes+ 32,700
Total Y-1 300,000

Portion priced as Belvieu Propane =27,396.3
Portion priced as Conway Propane =73,703.7
---------
Total Propane 100,100.0
</TABLE>

Note: 0.282 is a constant equal to the ratio of propane in EP mix (assumed to be
0.220 for purposes of this Agreement) to ethane in EP Mix (assumed to be 0.780
for purposes of this Agreement), as produced at Buyer's Borger NGL fractionator,
or 0.220/0.780 = 0.282.

<PAGE> 39

Exhibit D
TRANSPORTATION AND FRACTIONATION VARIABLES

<TABLE>
<CAPTION>
================ ======================= ===================== ====================== ================= ==================
Region Plant Name NGL Component Market Reference Transportation Market Frac
Price
- ---------------- ----------------------- --------------------- ---------------------- ----------------- ------------------
<S> <C> <C> <C> <C> <C>
C2 in EP Mix Belvieu OPIS $1.050 $0.580
Panhandle Rock Creek Y-1 C3 in EP Mix Belvieu OPIS $1.050 $0.580
Residual C3-C5+ Conway OPIS $0.500 $0.580

Sherhan Y-1 C2 in EP Mix Belvieu OPIS $1.150 $0.580
and Dumas Y-1 C3 in EP Mix Belvieu OPIS $1.150 $0.580
Residual C3-C5+ Conway OPIS $0.610 $0.580

Williams Skellytown All Components Conway OPIS $0.500 $0.580
(Note 1)

Sherhan, Dumas C2-C4 in Y-2 Conway OPIS $0.610 $0.580
Sneed, Rock Creek and Pentanes Plus WTI NYMEX $1.950 $0.900
Gray Y-2
- ---------------- ----------------------- --------------------- ---------------------- ----------------- ------------------
New Mexico Artesia All Components Belvieu OPIS $0.930 $0.660

Eunice All Components Belvieu OPIS $0.660 $0.660

Linam Ranch All Components Belvieu OPIS $0.640 $0.660

Seminole Clemens All Components Belvieu OPIS $0.100 $0.660
(Note 1)
- ---------------- ----------------------- --------------------- ---------------------- ----------------- ------------------
West Texas Fullerton All Components Belvieu OPIS $0.660 $0.660

Goldsmith All Components Belvieu OPIS $0.620 $0.660

Spraberry All Components Belvieu OPIS $0.660 $0.660

Benedum All Components Belvieu OPIS $0.660 $0.660

Seminole Clemens All Components Belvieu OPIS $0.100 $0.660
(Note 1)
- ---------------- ----------------------- --------------------- ---------------------- ----------------- ------------------
Austin Giddings All Components Belvieu OPIS $0.500 $0.660

Seminole Clemens All Components Belvieu OPIS $0.100 $0.660
(Note 1)
- ---------------- ----------------------- --------------------- ---------------------- ----------------- ------------------
Oklahoma Kingfisher All Components Conway OPIS $0.470 $0.580

Okarche All Components Conway OPIS $0.470 $0.580

Mooreland All Components Conway OPIS See (a) See (a)

Cimarron All Components Conway OPIS See (a) See (a)

Binger All Components Conway OPIS See (b) See (b)

Conway Frac All Components Conway OPIS $0.100 $0.580
- ---------------- ----------------------- --------------------- ---------------------- ----------------- ------------------

<CAPTION>
================ ======================= ============================================================
Region Plant Name Market Basis for Transportation fee Deduction
- ---------------- ----------------------- ------------------------------------------------------------
<S> <C> <C>
Negotiated settlement
Panhandle Rock Creek Y-1 Negotiated settlement
Negotiated settlement

Sherhan Y-1 Negotiated settlement
and Dumas Y-1 Negotiated settlement
Negotiated settlement

Williams Skellytown Panhandle Base T&F Fee
(Note 1)

Sherhan, Dumas Same as Sherhan-Dumas Y-1 C3+ components
Sneed, Rock Creek and Total Transportation plus market frac equals $2.85
Gray Y-2
- ---------------- ----------------------- ------------------------------------------------------------
New Mexico Artesia West Texas Pipeline LP Indian Basin to Mt. Belvieu tariff

Eunice West Texas Pipeline LP Eunice to Mt. Belvieu tariff

Linam Ranch Koch Chaparral Linam Ranch to Mt. Belvieu tariff

Seminole Clemens $0.100/Bbl Handling Fee
(Note 1)
- ---------------- ----------------------- ------------------------------------------------------------
West Texas Fullerton West Texas Pipeline LP Fullerton to Mt. Belvieu tariff

Goldsmith Koch Chaparral Goldsmith to Mt. Belvieu tariff

Spraberry West Texas Pipeline LP Fullerton to Mt. Belvieu tariff

Benedum West Texas Pipeline LP Fullerton to Mt. Belvieu tariff

Seminole Clemens $0.100/Bbl Handling Fee
(Note 1)
- ---------------- ----------------------- ------------------------------------------------------------
Austin Giddings Negotiated settlement

Seminole Clemens $0.100/Bbl Handling Fee
(Note 1)
- ---------------- ----------------------- ------------------------------------------------------------
Oklahoma Kingfisher Chisholm tariff plus negotiated settlement

Okarche Chisholm tariff plus negotiated settlement

Mooreland (a) T & F to be same as deducts in prevailing PPCO/Koch
agreement

Cimarron (a) T & F to be same as deducts in prevailing PPCO/Koch
agreement

Binger (b) T & F calculated as OPIS less actual Buyer's netback,
plus $0.05/Bbl

Conway Frac $0.100/Bbl Handling Fee
- ---------------- ----------------------- ------------------------------------------------------------
</TABLE>

Note 1. Applicable only if deliveries made at these locations with Buyer's
consent.

<PAGE> 40

EXHIBIT E
PROVISIONS REGARDING THE BENEDUM ANALYZER

1. Buyer will install an on-line analyzer instrument (the "Benedum Analyzer")
capable of sampling and measuring the NGL Components which are contained within
the aggregate NGL stream comprised predominately of NGL's from Seller's Plants
which are contained and flowing within Buyer's pipeline number 80-1-6, and
separately NGL's from Seller's Benedum plant. The Benedum Analyzer will be
located at or near the point at which such pipeline flows into Buyer's Benedum,
Texas Terminal. Buyer currently contemplates that it will set the instrument to
obtain and analyze NGL samples at approximately fifteen (15) minute intervals
throughout each Day (any such analysis being hereinafter referred to as a
"Periodic Analysis"). Buyer may, however, from time to time alter the sampling
and analysis frequency to such other intervals as, in Buyer's reasonable
judgment, will be sufficient for the provision of data from which Buyer may
calculate the components and other characteristics of the NGL's received at the
Benedum Plant each Day (each such calculated analysis being hereinafter referred
to as a "Daily Analysis"). The samples so obtained will be analyzed by a gas
chromatograph comprising an integral part of the instrument.

2. The Benedum Analyzer shall be utilized to determine, pursuant to Section 5.8,
the methane to ethane ratios of NGL's delivered from Seller's Plants within the
West Texas and New Mexico Regions which are contained and flowing within Buyer's
Spraberry Lateral pipeline number 80-1-6 at the Benedum terminal and, by
separate analysis, those NGL's delivered from Seller's Benedum Plant

3. Buyer may infrequently from time to time reverse the direction of flow of its
Mextex pipeline system such that NGL's from Buyer's Mextex system are introduced
into and commingled with Seller's NGL deliveries from the New Mexico and West
Texas Regions. In such event, Buyer shall notify Seller as to the time and
duration that the Mextex line reversal is expected to occur, and during the
period beginning the day the Mextex line is actually reversed and extending
until the fifth (5th) Day after the end of such reversal, the 1.75LV% peak ratio
value and the maximum methane to ethane ration of 1.25LV% shall not apply, and
the quality incentive bonus shall be calculated on the basis of the ethane
contained within the stream, as measured at the Benedum Analyzer.

4. In the event Buyer makes a connection with a third party plant such that
material quantities of NGL's from a party other than Seller or Seller's
Affiliates are routinely commingled with the NGL's delivered by Seller to Buyer
from the New Mexico or West Texas Regions, Buyer shall notify Seller with
respect to the same and the Parties shall agree as to how to accommodate the
additional third party NGL's with regard to testing of methane to ethane ratios
at the Benedum Analyzer for Seller's NGL's in line 80-1-6 . If the Parties fail
to reach agreement on a suitable alternate determination method, then the matter
shall be resolved pursuant to the dispute resolution procedure described in
Section 9.1(a) hereof.

<PAGE> 41

EXHIBIT F

FORM OF GUARANTEE

Whereas GPM Gas Corporation ("Subsidiary") [or Phillips 66 Company with
appropriate changes to references to the parties in the text below] has
entered into an NGL Supply Agreement (the "Agreement") with Phillips
Petroleum Company ("Phillips") for the sale and delivery of certain natural
gas liquids (NGL's) produced in the states of Texas, Oklahoma and New
Mexico;

Whereas, a ___________ ("Aquirer") has acquired all of the issued and
outstanding shares of stock of Subsidiary;

Whereas, ____________ Aquirer is an (indirect) subsidiary of parent of
__________("Parent');

Whereas the Parent desires that all of the rights and obligations under the
Agreement be rights and obligations of Subsidiary; and

Whereas, Phillips does not object to the Subsidiary's enjoying the rights
and bearing the obligations under the Agreement, provided that such
obligations are guaranteed by the Parent, and Parent is willing to
guarantee those obligations as hereinafter provided;

NOW THEREFORE, in consideration of Phillips' acquiescence to the
Subsidiary's remaining as the party to the Agreement, and as the Seller
thereunder, Parent agrees as follows:

1. Parent hereby, as a primary obligor, unconditionally and irrevocably
guarantees to Phillips the due, faithful and timely performance by the
Subsidiary (and by all other Affiliates as defined in the Agreement of the
Parent to which the Subsidiary might in the future assign rights or
obligations under the Agreement) of all obligations of the Subsidiary (or
such other Affiliates) under and arising out of the Agreement.

2. Parent further guarantees that Parent will provide the Subsidiary (directly
or through other Affiliates of the Parent) all resources reasonably
required in order for the Subsidiary to fulfill its obligations under the
Agreement.

3. This Guarantee is a continuing guarantee and shall remain in force until
all obligations of the Subsidiary under the Agreement have been discharged
in full.

4. This Guarantee and the obligations of Parent hereunder shall not be
affected by any act, omission or circumstance which, but for this
provision, might operate to release or otherwise exonerate the Parent from
its obligations hereunder or affect

<PAGE> 42

such obligations including without limitation (i) the bankruptcy or
insolvency of the Subsidiary, or any amendment, modification, extension,
waiver, indulgence (including extension of time) or concession made or
granted to Subsidiary, (ii) the taking, variation, compromise, renewal or
release of, or refusal or neglect to perfect or enforce, the Agreement or
any rights, remedies or securities against or granted by Subsidiary, or
(iii) the unenforceability of any obligations of Subsidiary under the
Agreement.

5. The Parent waives any right it may have to require Phillips to proceed
against or claim payment from Subsidiary or enforce any guarantee or
security granted by any other person before making a demand against Parent
under this Guarantee.

6. Each demand by Phillips for payment under this Guarantee shall be made in
writing addressed as follows:

Parent shall promptly notify Phillips of any change in its address for the
presentation of demands hereunder.

7. This Guarantee shall be governed by and construed and interpreted in
accordance with the laws of the State of Texas applicable to contracts made
and to be enforced in such jurisdiction. Parent and Phillips hereby submit
to the exclusive jurisdiction of the United States District Court for the
___________ District of __________ (or, in the event that such court lacks
jurisdiction, to the courts of general jurisdiction of the State of _______
sitting in ___________) for purposes of the enforcement of this Guarantee
and the resolution of any claim, dispute or controversy arising hereunder.

8. Phillips shall give Parent not less than thirty-(30) days' written notice
before commencing any proceedings to enforce this Guarantee.

Executed as of the __ day of ___________, ______.

(Parent )

By:
-------------------------------

Title:
----------------------------

<PAGE> 43

EXHIBIT G
BUSHTON PLANT SYSTEMS

GPM Panhandle Region Gathering Systems
Purchased from Enron and ANR

<TABLE>
<S> <C>
- ------------------------------------- ----------------------------------------------------
Beaver County #5 Mendota
- ------------------------------------- ----------------------------------------------------
Beaver County #6 Red Deer
- ------------------------------------- ----------------------------------------------------
Beaver County #7 Griggs
- ------------------------------------- ----------------------------------------------------
Beaver County #9 Morrison
- ------------------------------------- ----------------------------------------------------
Woodward County #1 NNG/GPM Kaiser-Francis Baker 1-10
- ------------------------------------- ----------------------------------------------------
Woodward County #2 NNG Weber #23-7
- ------------------------------------- ----------------------------------------------------
Woodward County #3 NNG Dude Wilson
- ------------------------------------- ----------------------------------------------------
Beaver County #11 Beaver County #1
- ------------------------------------- ----------------------------------------------------
Beaver County #12 NNG/GPM Paulson #1-2 PDC
- ------------------------------------- ----------------------------------------------------
Beaver County #13 Harvey/Thurmond
- ------------------------------------- ----------------------------------------------------
Spearman Compressor NNG/Dewey #1 PDC
- ------------------------------------- ----------------------------------------------------
ANR/GPM Lovedale GPM/NNG State of Texas I/C
- ------------------------------------- ----------------------------------------------------
ANR/GPM North Lovedale Bridges B-17
- ------------------------------------- ----------------------------------------------------
ANR/GPM Laverne NNG/GPM THIERSTEIN PDC
- ------------------------------------- ----------------------------------------------------
ANR/GPM Lovedale C NNG/GPM JAHNEL PDC
- ------------------------------------- ----------------------------------------------------
East Clinton NNG/GPM MALES/EARLE PDC
- ------------------------------------- ----------------------------------------------------
CCPL Redmoon NNG/GPM MATHERS 1-27 PDC
- ------------------------------------- ----------------------------------------------------
Turkey Gathering NNG/GPM MOLLY #1 PDC
- ------------------------------------- ----------------------------------------------------
Burnett Compressor NNG/GPM THOMAS HILL #1
- ------------------------------------- ----------------------------------------------------
BOYD UNIT INTERCONNECT NNG/GPM GUENZAL/SPURLIN PDC
- ------------------------------------- ----------------------------------------------------
Gregory #2-16 NNG/GPM PDC NNG/GPM MERRICK PDC
- ------------------------------------- ----------------------------------------------------
Farnsworth (NNG) NNG/GPM ROGER MILLS PDC
- ------------------------------------- ----------------------------------------------------
Lipscomb County #2 NNG/GPM FEE PDC
- ------------------------------------- ----------------------------------------------------
Clark County #1 NNG/GPM SANDERS A-74 PDC
- ------------------------------------- ----------------------------------------------------
Clark County #2 NNG/GPM LEELAND PDC
- ------------------------------------- ----------------------------------------------------
Beaver County #15 NNG/GPM BOX ELDER PDC
- ------------------------------------- ----------------------------------------------------
Ellis County #1 Hemphill County #1
- ------------------------------------- ----------------------------------------------------
Ellis County #2 NNG/GPM Logsdon #1-4 PDC
- ------------------------------------- ----------------------------------------------------
Ellis County #3 NNG/GPM Cates PDC
- ------------------------------------- ----------------------------------------------------
Ellis County #4 Hemphill County #2
- ------------------------------------- ----------------------------------------------------
NNG/GPM Feil #1 PDC Hemphill County #3
- ------------------------------------- ----------------------------------------------------
Doby, Glenwood, Hamm, Stockholm Hutchinson County #1
- ------------------------------------- ----------------------------------------------------
Lips/Higgins/Bussard Delivery Beaver County #2
- ------------------------------------- ----------------------------------------------------
Lockhart (PH Lateral P-1) Lipscomb County #1
- ------------------------------------- ----------------------------------------------------
Coburn Delivery Point Beaver County #3
- ------------------------------------- ----------------------------------------------------
Feldman Northrup
- ------------------------------------- ----------------------------------------------------
Wiggins Delivery Point
- ------------------------------------- ----------------------------------------------------
Mathers Humphries
- ------------------------------------- ----------------------------------------------------
Leedy/Beal
- ------------------------------------- ----------------------------------------------------
Blackketter Delivery Point
- ------------------------------------- ----------------------------------------------------
Hammon
- ------------------------------------- ----------------------------------------------------
Canadian (Parnell, Parsell, Waka) O:\LEGAL\GPM Stock-JV deals CONF\NGL Agreement final
11-30-99.doc
- ------------------------------------- ----------------------------------------------------
</TABLE>
<PAGE> 44

AMENDMENT NO. 1 TO
NGL OUTPUT PURCHASE AND SALE AGREEMENT

This Amendment No. 1 dated as of December 16, 1999, amends the NGL
OUTPUT PURCHASE AND SALE AGREEMENT ("Agreement") executed by the parties on
December 1 and 2, 1999, and dated as of January 1, 2000, by and between PHILLIPS
66 COMPANY, a division of PHILLIPS PETROLEUM COMPANY, a Delaware corporation
("Buyer"), and GPM GAS CORPORATION, a Delaware corporation ("Seller"). Buyer and
Seller are sometimes referred to individually herein as a "Party" and
collectively as the "Parties."

Phillips Petroleum Company ("Phillips") is considering entering into a
Contribution Agreement and related agreements with Duke Energy Corporation
("Duke") under which Duke and Phillips would contribute subsidiaries owning gas
gathering and processing assets including Seller to a new holding company
("Holding Company"). Under the contemplated agreement, Duke Energy Field
Services Inc. and its related subsidiaries (collectively "DEFS") would also be
contributed to the Holding Company. This Amendment No. 1 shall only be effective
if the Holding Company is formed and DEFS and its subsidiaries and the Phillips
subsidiaries are contributed to it.

In consideration of the premises and of the mutual covenants contained
herein, the parties agree to amend the Agreement as follows:

1. DEFS EXCLUSION FROM COMMITMENT. (a) Buyer and Seller agree that
subject to the other provisions of this Amendment, and in particular except as
stated in Paragraph 3 below, NGL production from facilities owned or controlled
by DEFS as of the date of contribution of DEFS and its subsidiaries to the
Holding Company shall not be committed or dedicated under the Agreement, even if
after the formation of the Holding Company DEFS or companies included in DEFS
are merged with Seller or DEFS gathering facilities are otherwise integrated
with those of Seller. Notwithstanding the foregoing, any additions to the NGL
production facilities or changes in the gas plant supplies owned and controlled
by DEFS that occur during the interim period between the effective date of the
Agreement and the date of contribution of DEFS and its subsidiaries to the
Holding Company to the extent that they involve any NGL's that are owned or
controlled or purchased or exchanged by Phillips as of the date of the Agreement
shall remain committed and dedicated to Phillips under the respective
controlling agreements.

(b) The definition of "New Plants" in Section 1.1(o) of the Agreement
is revised to read as follows:

(o) New Plant" means a gas processing plant not described on "A" at
which Seller delivers or intends to deliver natural gas located
within the counties listed in the definition of each Region and all
areas within 25 miles of those counties.

<PAGE> 45

2. DIVERSION. Section 3.2(c) is revised to read as follows:

(c) Seller covenants to Buyer that it will not enter into
business combinations, contracts or agreements, or otherwise modify its
normal business practices, which have as their purpose or as a
significant effect the reduction or diversion of the quantities of
NGL's to be delivered and sold by Seller to Buyer hereunder (by the
diversion of raw gas supplies out of any Region, or otherwise), or any
circumvention of Seller's other obligations hereunder.

3. INCREASES IN NGL PRODUCTION CAPACITY. Sections 3.4 and 3.5 of the
Agreement are amended as follows. After formation of the Holding Company, in the
event Seller or Holding Company anticipates or causes an increase in the
quantity of NGL's at any source of NGL production committed under the Agreement
or at any DEFS NGL production source and such increase results from any single
addition of processed gas volumes of 10 MMcf per day or more at the time of the
addition, Buyer shall have the right to purchase 40% of the NGL's associated
with those increased volumes under the Agreement. The provisions of Section 3.4
will apply to these additions for purposes of arranging for purchase, sale and
delivery of the affected NGL's to Buyer.

4. PLANT CONSOLIDATIONS WITH DEFS. The contemplated Holding Company
will desire to achieve operating efficiencies resulting from the combination of
assets, and may consider consolidations of Seller and DEFS assets as permitted
in Section 3.7 of the Agreement. In the event the Holding Company causes one or
more consolidations of its owned or controlled gas gathering and processing
assets between former DEFS facilities and Seller facilities, the volume of NGL
production committed to Buyer under this Agreement affected by such a
consolidation will be equal to a percentage of future production from the
consolidated facilities where such percentage shall be calculated by taking the
volume of NGL production committed to Buyer at the consolidated facilities
divided by the total NGL production of the consolidated facilities, both
determined where applicable over the prior 12 months. Sample calculations of
such volumes and percentage are shown in two illustrative examples attached to
and incorporated by reference in this Amendment.

5. INDEMNIFICATION PROCEDURES. The last sentence of Section 5.4(c)(iii)
is amended to read as follows:

Provided however, the Indemnifying Party and its representatives shall
have the right to use or disclose to any third party information deemed
confidential by the Indemnified Party if the Indemnifying Party has
undertaken reasonable measures to protect the confidential nature of
the information during the proceedings.

6. BUYER OFFSETS. The last sentence of Section 6.1 is modified to read
as follows:

<PAGE> 46

Upon written notice to Seller, Buyer may withhold from and offset
against any amounts payable to Seller hereunder, any amounts payable by
Seller to Buyer under this Agreement or under any other agreement
between Buyer and Seller or Seller's affiliates other than affiliates
of Duke Energy Corporation not included in the Holding Company provided
for in the Contribution Agreement between Phillips and Duke Energy
Corporation, et al. dated as of December 16, 1999.

7. BUYER INDEMNIFICATION, NGL HANDLING. The following sentences are
added to the end of Section 8.2, Warranty of Title:

Buyer will defend, indemnify, and save Seller, its affiliates, and
their officers, agents, and employees harmless from all suits, claims,
liens, damages, costs (including attorneys' fees and costs of
litigation), losses, expenses, and encumbrances of whatsoever nature
arising from and out of claims of any or all persons of and concerning
title to NGL's delivered to Buyer and claims for royalties, taxes,
license fees, payments and other charges thereon applicable after the
title transfers to Buyer; provided however, that this sentence shall
not apply, and Seller shall indemnify Buyer and the Buyer Indemnitees
for Off-Specification NGL's as stated in Section 5.4. The
indemnification procedures of Section 5.4(c) will apply to requests for
indemnification under this Section 8.2.

8. EXHIBIT F FORM OF GUARANTEE. The Guarantee in the form of Exhibit F
if required shall be executed by Seller's direct parent company, and no parent
of that company shall be required to execute a Guarantee in the form of Exhibit
F.

9. COUNTERPARTS. This Agreement may be executed in one or more
counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.

10. SCOPE. The Agreement is amended to the extent noted herein. In all
other respects, it is confirmed and shall continue in full force and effect.

IN WITNESS WHEREOF, the Parties have set their hands by their duly
authorized officials as of the date set forth above.

PHILLIPS 66 COMPANY, a division of GPM GAS CORPORATION
PHILLIPS PETROLEUM COMPANY

By: /s/ B.Z. PARKER By: /s/ M.J. PANATIER
--------------------------------- ----------------------------------
Title: Executive Vice President Title: President
------------------------------- -------------------------------

Executed on: December 1, 1999 Executed on: December 2, 1999
------------------------- -------------------------

<PAGE> 47

ATTACHMENT A TO AMENDMENT NO. 1
TO NGL OUTPUT PURCHASE AND SALE AGREEMENT

Provided below are two examples illustrating how the percentage and committed
volumes are to be determined under Section 3.7 of the Agreement as amended by
Paragraph 4 of this Amendment.

EXAMPLE 1. GPM OR GPM NON-OPERATED PLANT NGL'S DISPLACED TO DEF'S PLANT.

<TABLE>
<S> <C>
Date of Displacement is 6/15/2000

NGL Production for the period June 1999 through May 2000.

GPM CO-OWNED PLANT, PARTIALLY COMMITTED BBLS/YR.

GPM Owned and Controlled NGL's to Phillips 1,768,425
In-Kind NGL's due GPM contracted to Third Parties 141,620
Uncommitted Portion that is Co-owner Owned 2,464,845
---------
Total NGL's from Plant 4,374,890

DEFS PLANT BBLS/YR.

DEFS Owned and Controlled NGL's 1,200,485
In-Kind NGL's due DEFS contracted to Third Parties 4,550,820
---------
Total NGL's from Plant 5,751,305

SHARE TO BE COMMITTED TO PHILLIPS
(1,768,425 + 141,620) /
(1,768,425 + 141,620 + 5,751,305) WHICH EQUALS 24.93%

NGL production during a month subsequent to the displacement

CONSOLIDATED PRODUCTION AT DEFS PLANT BBLS/MO.

DEFS Owned and Controlled NGL's 100,000
In-Kind NGL's due DEFS Affiliated Third Parties 380,000
Uncommitted Portion that is GPM Co-owner Owned 0
Additional NGL's due to Consolidation 165,000
-------
Total NGL's from Plant 645,000

MONTHLY VOLUMES DELIVERED AND SOLD TO PHILLIPS
(645,000 X 0.2493) = 160,804
</TABLE>

<PAGE> 48

EXAMPLE 2. DEFS PLANT NGL'S DISPLACED TO GPM PLANT CONTAINING DISPLACED DEFS
NGL'S.

<TABLE>
<S> <C>
Date of Displacement is 6/15/2001

NLG Production for the period June 2000 through May 2001.

GPM PLANT COMMITTED TO PHILLIPS BBLS/YR.

GPM Owned and Controlled NGL's TO PHILLIPS 3,593,425
In-Kind NGL's due GPM contracted to Third Parties 506,620
DEFS Owned and Controlled Uncommitted NGL's 1,204,135
---------
Total NGL's from Plant 5,304,180

DEFS PLANT BBLS/YR.

DEFS Owned and Controlled NGL's 1,200,485
In-Kind NGL's due DEFS contracted to Third Parties 4,550,820
---------
Total NGL's from Plant 5,751,305

SHARE TO BE COMMITTED TO PHILLIPS
(3,593,425 + 506,620) /
(5,304,180 + 5,751,305) WHICH EQUALS 37.09%

NGL production during a month subsequent to the displacement

CONSOLIDATED NGL'S AT GPM PLANT BBLS/MO.

GPM Owned and Controlled NGL's 300,000
In-Kind NGL's due Third Parties by GPM 42,000
DEFS Owned and Controlled Uncommitted NGL'S 100,000
Additional NGL's due to Consolidation 480,000
-------
Total NGL's from Plant 922,000

MONTHLY VOLUMES DELIVERED AND SOLD TO PHILLIPS
(922,000 X 0.3709) = 341,934
</TABLE>

<PAGE> 1

EXHIBIT 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the reference to our firm under the caption "Experts" and to
the use of our report dated March 6, 2000, with respect to the financial
statements of Phillips Gas Company included in the Registration Statement (Form
S-1) and related Prospectus of Duke Energy Field Services Corporation for the
registration of its common stock.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 13, 2000

<PAGE> 1

EXHIBIT 23.2

INDEPENDENT AUDITORS' CONSENT

We consent to the use in this Registration Statement of Duke Energy Field
Services Corporation on Form S-1 of our reports dated February 18, 2000 and June
12, 1998, appearing in the Prospectus which is a part of this Registration
Statement.

We also consent to the reference to us under the heading "Experts" in such
Prospectus.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 14, 2000

<PAGE> 1

Exhibit 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the use of our
report on the combined statements of income and cash flows of the UP Fuels
Division of Union Pacific Resources Group Inc. for the three-month period ended
March 31, 1999 and the year ended December 31, 1998 (and to all references to
our Firm) included in or made a part of this registration statement.

/s/ ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 14, 2000

<ARTICLE> 5
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JAN-01-1999
<CASH> 792
<SECURITIES> 0
<RECEIVABLES> 440,809
<ALLOWANCES> 6,743
<INVENTORY> 38,701
<CURRENT-ASSETS> 518,256
<PP&E> 3,005,510
<DEPRECIATION> 596,125
<TOTAL-ASSETS> 3,471,835
<CURRENT-LIABILITIES> 2,640,585
<BONDS> 0
0
0
<COMMON> 1
<OTHER-SE> 386,470
<TOTAL-LIABILITY-AND-EQUITY> 3,471,835
<SALES> 3,310,260
<TOTAL-REVENUES> 3,458,310
<CGS> 2,965,297
<TOTAL-COSTS> 3,146,689
<OTHER-EXPENSES> 130,788
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 52,915
<INCOME-PRETAX> 74,358
<INCOME-TAX> 31,029
<INCOME-CONTINUING> 43,329
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 43,329
<EPS-BASIC> 0.00
<EPS-DILUTED> 0.00

</TABLE>

<PAGE> 1
EXHIBIT 99.1

CONSENT

The undersigned hereby consents to being named in the Registration
Statement on Form S-1 (the "Registration Statement") of Duke Energy Field
Services Corporation ("DEFS") as a director to be appointed after the
consummation of the initial public offering (the "IPO") of DEFS. The undersigned
further consents to serve as a director of DEFS following the consummation of
the IPO.

IN WITNESS WHEREOF, the undersigned has executed this Consent effective as
of the 13th day of March, 2000.

/s/ M. J. PANATIER
------------------------
Mike J. Panatier

<PAGE> 1
EXHIBIT 99.2

CONSENT

The undersigned hereby consents to being named in the Registration
Statement on Form S-1 (the "Registration Statement") of Duke Energy
Field Services Corporation ("DEFS") as a director to be appointed after
the consummation of the initial public offering (the "IPO") of DEFS.
The undersigned further consents to serve as a director of DEFS following
the consummation of the IPO.

IN WITNESS WHEREOF, the undersigned has executed this Consent
effective as of the 10th day of March, 2000.

/s/ J. J. MULVA
---------------------------
J. J. Mulva