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

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FORM 10-K

<Table>

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

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

FOR THE TRANSITION PERIOD FROM TO
</Table>

COMMISSION FILE NUMBER 0-31095

DUKE ENERGY FIELD SERVICES, LLC
(Exact name of registrant as specified in its charter)

<Table>

DELAWARE 76-0632293
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

370 17TH STREET, SUITE 900 80202
DENVER, COLORADO (Zip Code)
(Address of principal executive offices)
</Table>

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE
303-595-3331

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

<Table>
<Caption>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------

None Not Applicable
</Table>

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
LIMITED LIABILITY COMPANY MEMBER INTERESTS
(Title of class)

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months or for such shorter period that the
registrant was required to file such reports and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

As of March 22, 2002, 69.7% of the registrant's outstanding member
interests is beneficially owned by Duke Energy Corporation and 30.3% is
beneficially owned by Phillips Petroleum Company. The aggregate market value of
the voting member interests held by non-affiliates of the Registrant as of March
22, 2002 was $0.

DOCUMENTS INCORPORATED BY REFERENCE:
NONE
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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001

TABLE OF CONTENTS

<Table>
<Caption>
ITEM PAGE
- ---- ----

PART I
1. Business.................................................... 3
Our Business................................................ 3
Our Business Strategy....................................... 4
Natural Gas Gathering, Processing, Transportation, Marketing
and Storage................................................. 5
Natural Gas Liquids Transportation, Fractionation and
Marketing................................................... 12
TEPPCO...................................................... 13
Natural Gas Suppliers....................................... 14
Competition................................................. 15
Regulation.................................................. 15
Environmental Matters....................................... 18
Employees................................................... 19
2. Properties.................................................. 19
3. Legal Proceedings........................................... 19
4. Submission of Matters to a Vote of Security Holders......... 19

PART II
5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 19
6. Selected Financial Data..................................... 21
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 23
7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 34
8. Financial Statements and Supplementary Data................. 39
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 69

PART III
10. Directors and Executive Officers of the Registrant.......... 69
11. Executive Compensation...................................... 71
12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 74
13. Certain Relationships and Related Transactions.............. 75

PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K......................................................... 77
Signatures........................................................ 78
</Table>

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements may from time to time
contain 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 of such statements other than statements of historical facts, 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.

These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors, many of which are outside our control.
Important factors that could cause actual results to differ materially from the
expectations expressed or implied in the forward-looking statements include
known and unknown risks. Known risks include, but are not limited to, the
following:

- our ability to access the debt and equity markets, which will depend on
general market conditions and the credit ratings for our debt
obligations;

- our use of derivative financial instruments to hedge commodity and
interest rate risks;

- the level of creditworthiness of counterparties to transactions;

- changes in laws and regulations, particularly with regard to taxes,
safety and protection of the environment or the increased regulation of
the gathering and processing industry;

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

- weather and other natural phenomena;

- industry changes, including the impact of consolidations, and changes in
competition;

- 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; and

- the effect of accounting policies issued periodically by accounting
standard-setting bodies.

In light of these risks, uncertainties and assumptions, the events
described in the forward-looking statements might not occur or might occur to a
different extent or at a different time than we have described.

PART I

ITEM 1. BUSINESS

Duke Energy Field Services, LLC is a company formed in 1999 that holds the
combined North American midstream natural gas gathering, processing, marketing
and natural gas liquids ("NGL") business of Duke Energy Corporation ("Duke
Energy") and Phillips Petroleum Company ("Phillips"). The transaction in which
those businesses were combined is referred to in this Form 10-K as the
"Combination." Our limited liability company agreement limits the scope of our
business to the midstream natural gas industry in the United States and Canada,
the marketing of NGLs in Mexico and the transportation, marketing and storage of
other petroleum products, unless otherwise approved by our Board of Directors.

Unless the context otherwise requires, descriptions of assets, operations
and results in this Form 10-K 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." In this Form 10-K, the terms "the
Company," "we," "us" and "our" refer to Duke Energy Field Services, LLC and our
subsidiaries, giving effect to the Combination and related transactions.

From a financial reporting perspective, we are the successor to Duke
Energy's North American midstream natural gas business. The subsidiaries of Duke
Energy that conducted this business were contributed to us immediately prior to
the Combination. For periods prior to the Combination, Duke Energy Field
Services and these subsidiaries of Duke Energy are collectively referred to
herein as the "Predecessor Company."

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

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
("Natural Gas Segment"); and

- NGL fractionation, transportation, marketing and trading ("NGL Segment").

- we handled an average of approximately 8.6 trillion British thermal units
("Btus") per day of raw natural gas;

- we produced an average of approximately 397,000 barrels per day of NGLs;
and

- we marketed and traded an average of approximately 565,000 barrels per
day of NGLs.

We gather raw natural gas through gathering systems located in seven major
natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin
Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of
Mexico and Western Canada. Our gathering systems consist of approximately 57,000
miles of gathering pipe, with approximately 40,000 active receipt points.

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 64 owned and operated
plants and at 12 third party operated facilities in which we hold an equity
interest.

The NGLs separated from the raw natural gas by our processing operations
are either sold and transported as NGL raw mix or further separated through a
process known as fractionation into their individual components (ethane,
propane, butanes and natural gasoline) and then sold as components. We
fractionate NGL raw mix at our 12 owned and operated fractionators 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 and Chevron Phillips Chemical Company LLC under an existing contract
which expires December 31, 2014. In addition, we use trading and storage to
manage our price risk and provide additional services to our customers. (See
"Natural Gas Liquids Transportation, Fractionation and Marketing" in this
section.)

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 9.0 billion cubic foot natural gas storage facility.

On March 31, 2000, we combined the gas gathering, processing, marketing and
NGLs businesses of Duke Energy and Phillips. In connection with the Combination,
Duke Energy and Phillips transferred all of their respective interests in their
subsidiaries that conducted their midstream natural gas business to us.
Concurrent with the Combination, 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
and storage and terminal facilities for refined products, liquefied petroleum
gases, liquefied natural gas, petrochemicals, natural gas gathering and crude
oil. The general partner is responsible for the management and operations of
TEPPCO. We believe that our ownership of the general partner of TEPPCO improves
our business position in the transportation sector of the midstream natural gas
industry and provides additional flexibility in pursuing our disciplined
acquisition strategy by providing an alternative acquisition vehicle. It also
provides us with an opportunity to sell appropriate assets currently held by our
company to TEPPCO.

A discussion of the current business and operations of each of our segments
follows. For further discussion of these segments, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations." For financial
information concerning our business segments, see Note 17, "Business Segments,"
of the Notes to Consolidated Financial Statements.

OUR BUSINESS STRATEGY

We believe that we are one of the largest gatherers of raw natural gas,
based on wellhead volume, in North America. We are the largest producer, and we
believe that we are one of the largest marketers, of NGLs in North America. Our
limited liability company agreement limits the scope of our business to the
midstream natural gas industry in the United States and Canada, the marketing of
NGLs in Mexico, and the transportation, marketing and storage of other petroleum
products, unless otherwise approved by our board of directors. We have
significant midstream natural gas operations in five of the largest natural gas
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 with a competitive advantage in
capturing new supplies of raw natural gas because of our resulting lower
costs of connection to new wells and of processing additional raw natural
gas. In addition, we believe our size and geographic diversity allow us
to benefit from the growth of natural gas production in multiple regions
while mitigating the adverse effects from a downturn in any one region.

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

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

- Capitalize on proven acquisition skills in a consolidating industry. In
addition to pursuing internal growth by attracting new raw natural gas
supplies, we intend to use our substantial acquisition and integration
skills to continue to participate selectively in the consolidation of the
midstream natural gas industry. We have pursued a disciplined acquisition
strategy focused on acquiring complementary assets during periods of
relatively low commodity prices and integrating the acquired assets into
our operations. Since 1996, we have completed over 30 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.

NATURAL GAS GATHERING, PROCESSING, TRANSPORTATION, MARKETING AND STORAGE

OVERVIEW

At December 31, 2001, our raw natural gas gathering and processing
operations consisted of:

- approximately 57,000 miles of gathering pipe, with connections to
approximately 40,000 active receipt points; and

- 64 owned and operated processing plants and ownership interests in 12
additional third party operated plants, with a combined processing
capacity of approximately 8.0 billion cubic feet per day.

In 2001, we gathered, processed and/or transported approximately 8.6
trillion Btus per day of raw natural gas. During 2001, our natural gas
gathering, processing, transportation, marketing and storage activities produced
$1.2 billion of gross margin.

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. According to the "Gas Processors Report" dated July 2, 2001,
we are the largest NGL producer.

Raw Natural Gas Supply Arrangements. Typically, we take ownership, control
or custody 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 obtain access to raw natural gas and provide our
midstream natural gas service principally under three types of contracts:
percentage-of-proceeds contracts, fee-based contracts and keep-whole contracts.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Overview -- Effects of Our Raw Natural Gas Supply Arrangements"
for a description of these types of contracts.

Raw Natural Gas Gathering. As of December 31, 2001, we had over 20
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 Phillips, Anadarko
Petroleum, EOG Resources, Exxon Mobil, and Louis Dreyfus Natural Gas, which
together account for approximately 20% of our processed raw natural gas.

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

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

We believe our significant asset base and scope of our operations provide
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,
according to the EIA Report contain significant quantities of proved natural gas
reserves. We also have a presence in other potential high-growth areas such as
the Western Canadian Sedimentary Basin. As a result of new connections resulting
from both increased drilling and released raw natural gas, we connected
approximately 2,800 additional receipt points in 2001.

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

Raw Natural Gas Processing. Most of our natural gas gathering systems feed
into our natural gas processing plants. Our processing plants received an
average of approximately 6.6 trillion Btus per day of raw gas and produced an
average of 397,000 barrels per day of NGLs during 2001.

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.

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.

Our Spindletop storage facility plays an important role in our ability to
act as a full-service natural gas marketer. We lease over half 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, provide "backup" service
to our customers and support our trading activities.

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.

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. Our
geographic diversity reduces the impact of regional price fluctuations and
regional changes in drilling activity.

Our raw natural gas gathering and processing assets are managed in line
with the seven geographic regions in which we operate. The following table
provides information concerning the raw natural gas gathering systems and
processing plants owned or operated by us at December 31, 2001.

<Table>
<Caption>
2001 OPERATING DATA
GAS PLANTS -------------------------
GATHERING COMPANY OPERATED NET PLANT PLANT INLET NGLS
SYSTEM OPERATED BY CAPACITY(1) VOLUME(1) PRODUCTION
REGION (MILES) PLANTS OTHERS (MMcf/d)(3) (BBtu/d)(3) (Bbls/d)(3)
- ------ --------- -------- -------- ----------- ----------- -----------

Permian Basin............ 13,400 17 2 1,380 1,391 124,928
Mid-Continent............ 29,759 14 2 2,119 1,910 123,992
East Texas-Austin Chalk-
North Louisiana........ 5,541 8 - 1,352 1,161 68,725
Onshore Gulf of Mexico... 3,775 7 1 1,118 1,044 46,798
Rocky Mountains.......... 3,400 10 1 640 503 26,421
Offshore Gulf of
Mexico................. 452 2 5 1,100 270(2) 4,968
Western Canada........... 921 6 1 543 311 1,472
------ -- -- ----- ----- -------
Total.................... 57,248 64 12 8,252 6,590 397,304
</Table>

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(1) Note that while capacity is measured volumetrically (in cubic feet), inlet
volumes are measured using heating value (in British thermal units).

(2) Excludes inlet volumes of about 470 BBtu/d net for plants operated by
others.

(3) MMcf/d: million cubic feet per day; BBtu/d: billion British thermal units
per day; Bbls/d: barrels per day.

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 gatherers, 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.

- 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 to increase utilization and operating efficiencies and realize
economies of scale.

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

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

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

Permian Basin. Our facilities in this region are located in West Texas and
Southeast New Mexico. We own majority interests in and are the operator of 17
natural gas processing plants in this region. In addition, we own minority
interests in two other natural gas processing plants that are operated by
others. Our natural gas processing plants are strategically located to access
Permian Basin production. 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, processing, and marketing of
natural gas and NGLs. We offer low, intermediate and high pressure gathering
services, and processing and treating services for both sweet and sour gas
production. 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 some of
our plants include facilities for the production of sulfur. During 2001, these
plants operated at an overall 82% capacity utilization rate. On average, the raw
natural gas from West Texas and New Mexico contains approximately 5.0 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 increases 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 Exxon Mobil, Occidental, Anadarko
Petroleum, Phillips, Dominion, Chevron-Texaco, and Yates Petroleum. Our
principal competitors in this region include Dynegy,

Sid Richardson, Conoco, Western Gas, British Petroleum, El Paso Field Services,
Marathon and Chevron-Texaco.

Mid-Continent. Our facilities in this region are located in Oklahoma,
Kansas, the Texas Panhandle and the Ladder Creek area of Southeast Colorado. In
this region, we own and are the operator of 14 natural gas processing plants. We
also own minority interests in two other natural gas processing plants that are
operated by others. We gather and process raw natural gas primarily from the
Arkoma, Ardmore, and Anadarko basins, including the prolific Hugoton and
Panhandle fields. Our plants have processing capacity net to our interest of 2.1
billion cubic feet of raw natural gas per day. During 2001, our plants operated
at an overall 77% capacity utilization rate. On average, the raw natural gas
from this region contains 4.2 gallons of NGLs per thousand cubic feet.

We also produce approximately 30% of the United States' domestic supply of
helium from our Mid-Continent facilities. Annual growth in demand for helium
over the past 15 years has been approximately 8.5% per year. Because of its
unique characteristics and use as an industrial gas, we expect demand for helium
to grow well into the future.

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

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

East Texas-Austin Chalk-North Louisiana. Our facilities in this region are
located in East Texas, North Louisiana and the Austin Chalk formation of East
Central Texas and Central Louisiana. We own majority interests in and are the
operator of eight natural gas processing plants in this region. Our plants have
processing capacity net to our interest of 1.4 billion cubic feet of raw natural
gas per day. During 2001, these plants operated at an overall 74% capacity
utilization rate.

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. The plant is connected to and processes raw natural gas from our own
gathering systems as well as from several third party gathering systems,
including those owned by Koch, Anadarko Petroleum and American Central. Most of
the raw natural gas processed at the complex is contracted under
percent-of-proceeds agreements with an average remaining term of approximately
five years. This plant is adjacent to our Carthage Hub, which delivers residue
gas to interconnects with 12 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.

In the Austin Core area, where we provide essential low pressure gathering
and compression services, infill drilling and recompletion activity continues to
offset the lower decline rates of this mature production area. Given the
maturity of this area, consolidation of our own facilities and/or consolidation
with other gathering and processing companies could occur. In the Eastern Chalk
area (Brookeland and Masters Creek) where we are in the process of consolidating
facilities, reduced activity and declining volumes are expected to continue.
Additional improvements in technology could significantly increase activity and
reserve recovery in either of these areas.

In North Louisiana, we gather and process or gather and transport over
420,000 million Btu/d. We operate one of the largest intrastate pipelines in
Louisiana, our PELICO System, which delivers gas to industrial customers and
electric generators within the state and also makes deliveries to six interstate
pipelines at or near the Perryville Hub.

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 Anadarko Petroleum, Devon and
Phillips. Our principal competitors in this region include Koch, El Paso Field
Services and Aquila Southwest Pipeline Corporation.

Onshore Gulf of Mexico. Our facilities in this region are located in South
Texas and the Southeastern portions of the Texas Gulf Coast. We own a 100%
interest in and are the operator of seven natural gas processing plants and the
Spindletop gas storage facility in this region. In addition, we own a minority
interest in one natural gas processing plant that is operated by another entity.
Our plants have processing capacity net to our interest of 1.1 billion cubic
feet of raw natural gas per day. During 2001, the plants in this region ran at
an overall 83% capacity utilization rate.

Our Spindletop natural gas storage facility is located near Beaumont, Texas
and has current working natural gas capacity of 9.0 billion cubic feet, plus
expansion potential of up to an additional 10 billion cubic feet. We currently
have approximately 5.0 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 10 interstate and
intrastate pipelines and is designed to handle the hourly demand needs of power
generators.

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

Our key suppliers in this region include Apache, United Oil and Minerals
and TransTexas. Our principal competitors in this region include El Paso Gas
Transmission, Co., 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 Greater Green River Basin and Overthrust Belt areas of
Southwest Wyoming and Northeast Utah. We own a 100% interest in and are the
operator of 10 natural gas processing plants in this region. In addition, we own
a minority interest in one natural gas processing plant that is operated by
another entity. Our plants have processing capacity net to our interest of 640
million cubic feet of raw natural gas per day. During 2001, our plants in this
region operated at an overall 72% capacity utilization rate. These assets
provide for the gathering and processing of raw natural gas and the
transportation and fractionation of NGLs.

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, British
Petroleum, Kerr McGee and Anadarko Petroleum. 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 an average
48% interest in and are the operator of two natural gas processing plants in
this region. In addition, we own a 51% interest in one natural gas processing
plant and minority interests in four other natural gas processing plants, all of
which are operated by other entities. The plants have processing capacity net to
our interest of 1.1 billion cubic feet of raw natural gas per day. During 2001,
our plants in this region operated at an overall 63% capacity utilization rate.
All of these plants straddle offshore pipeline systems delivering a lower
NGL-content gas stream than that of our onshore gathering systems.

In addition, we own a 71.8% interest in the Dauphin Island Gathering
Partners ("Dauphin Island"), a partnership which owns and operates an offshore
gathering and transmission system. Dauphin Island has attractive market outlets,
including deliveries to Texas Eastern Transmission, LP, Transco, Gulf South, 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, LP'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 33.3% 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 El Paso
Production Company, Exxon Mobil and Dominion. Our principal competitors in this
region include El Paso, Coral Energy, Enterprise, and Williams.

Western Canada. On May 1, 2001, we closed the acquisition of Canadian
Midstream Services Ltd. ("CMSL"). From CMSL, we acquired working interests in
the Brazeau area of west central Alberta, the Nevis area of southern Alberta and
the Peggo-Pesh area of northeast British Columbia. In total, we acquired 325
MMcf/d of sour gas processing capacity, 580 miles of gathering lines and 53,000
horsepower of compression from CMSL.

As a result of the CMSL transaction, we currently own interests in seven
natural gas processing plants in Western Canada and operate six of these plants.
These facilities are located in northeast British Columbia, the Peace River Arch
area of northwestern Alberta and the central foothills area of Alberta. In
total, the facilities in this region have processing capacity net to our
interest of 543 million cubic feet of raw sour natural gas per day. Over 900
miles of gathering systems and 100,000 horsepower of compression support these
facilities. During 2001, our processing plants in this area operated at an
overall 52% capacity utilization rate. Our processing facilities in this area
are new, with the majority having been constructed since 1995. Our processing
arrangements are primarily fee-based, providing an income stream that is not
subject to fluctuations in commodity prices. Our foreign operations in Canada
are subject to risks inherent in transactions involving foreign currencies.

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.

We believe that significant growth opportunities exist in this region. We
anticipate that producers in this area may follow the lead of United States
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 Burlington Resources Canada Ltd.,
Canadian Natural Resources Ltd., Alberta Energy Company and Devon Energy Canada.
Our principal competitors in the area include Gibson Gas Processing Ltd., BP
Amoco, Petro Canada and Keyspan Energy.

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 2001, our NGL transportation, fractionation and
marketing activities produced $55.4 million of gross margin and $49.0 million of
earnings before interest, taxes, depreciation and amortization ("EBITDA") (see
"Item 6. Selected Financial Data" footnote three for definition of EBITDA). In
2001, we marketed and traded approximately 565,000 barrels per day of NGLs, of
which approximately 73% was production for our own account, ranking us as one of
the largest NGL 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 an interest in the Black Lake Pipeline in Louisiana and East
Texas. We also own several regional fractionation plants and NGL pipelines.

In 2001, we acquired five propane rail terminals and constructed one in the
northeastern United States, establishing us as a prominent wholesale purchaser
and seller of propane in the Northeast. Marketing propane from these rail
terminals, along with volume from TEPPCO's Providence, Rhode Island import
facility, accounts for approximately 25,000 barrels per day of wholesale
business.

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 nine pipeline systems.
Our current fractionation capacity is approximately 164,000 barrels per day.

STRATEGY

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

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

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

49,500 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 NGL 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 NGL needs. Our largest suppliers are our own
plants and Anadarko Petroleum. Our largest sales customers are Chevron Phillips
Chemical Company, Phillips Chemical Company, Equistar Chemicals, Dow
Hydrocarbons and Huntsman, which accounted for approximately 15.0%, 13.0%, 5.0%,
4.0% and 3.0%, respectively, of our total NGL transportation, fractionation and
marketing revenues in 2001. Our three principal competitors in the marketing of
NGLs are El Paso, Dynegy and Williams. In 2001, we marketed and traded an
average of approximately 565,000 barrels per day, or approximately 21% of the
available domestic supply, which includes gas plant production, refinery plant
production and imports.

TEPPCO

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

- refined products, liquefied petroleum gases and petrochemicals
transportation (Downstream Segment);

- crude oil and NGLs transportation and marketing (Upstream Segment); and

- natural gas gathering (Midstream Segment).

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;

- intrastate transportation of petrochemicals;

- sale of product inventory;

- fractionation of NGLs; and

- ancillary services.

TEPPCO owns and operates an approximate 4,500 mile products pipeline
system, which includes storage facilities and delivery terminals, extending from
southeast Texas through central and midwest states to the northeast United
States. TEPPCO's asset base includes the only pipeline system that transports
liquefied petroleum gases to the northeast United States from the Texas Gulf
Coast. TEPPCO recently initiated a new service to the petrochemical industry
through the construction, ownership and operation of three pipelines in Texas
between Mont Belvieu and Port Arthur. TEPPCO also owns and operates
approximately 2,900 miles of crude oil gathering and trunk line pipelines and
approximately 650 miles of NGL pipelines, primarily in Texas
13

and Oklahoma. TEPPCO also owns a 50% interest in, and operates, a 500 mile large
diameter crude oil pipeline extending from the Texas Gulf Coast to Cushing,
Oklahoma. TEPPCO also owns interests in two joint venture crude oil pipelines
operating in New Mexico, Oklahoma and Texas. TEPPCO also owns a 300 mile
gathering system which gathers and transports natural gas from the Green River
Basin in southwestern Wyoming.

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

The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO
partnership agreement and the partnership agreements of its operating
partnerships. Under the partnership agreements, the general partner of TEPPCO is
reimbursed for all direct and indirect expenses it incurs and 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 2001 per unit distribution level, the general partner received
approximately 21% of the cash distributed by TEPPCO to its partners, which
consisted of 19% from the incentive cash distribution and 2% from the general
partner interest. During 2001, total cash distributions to the general partner
of TEPPCO were $22.0 million.

On January 9, 2002, TEPPCO announced that it had signed a definitive
agreement to acquire the Chaparral and Quanah NGL pipelines from Diamond-Koch
II, L.P. and Diamond-Koch III, L.P. for approximately $132.0 million. The
transaction closed on March 1, 2002. The Chaparral system is an 800 mile NGL
pipeline that extends from West Texas and New Mexico to Mont Belvieu, Texas. The
approximately 170 mile Quanah pipeline is a NGL gathering system located in West
Texas. The assets will be operated and commercially managed by us on behalf of
TEPPCO.

On September 30, 2001, TEPPCO completed the purchase of the Jonah Gas
Gathering Company ("Jonah") from Alberta Energy Company for approximately $360.0
million. The acquisition serves as an entry for TEPPCO into the natural gas
gathering industry. The 300 mile Jonah system gathers and transports natural gas
from the Green River Basin in southwestern Wyoming, one of the most prolific and
active basins in the United States. The Jonah system is commercially managed and
operated by us on behalf of TEPPCO.

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 2001. 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 consider our relations with our many producers to be good.
For a description of the types of contracts we have entered into with our
suppliers, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Overview -- Effects of Our Raw Natural Gas Supply
Arrangements."

COMPETITION

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

- major integrated oil companies;

- major interstate and intrastate pipelines or their affiliates;

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

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

Competition for raw natural gas supplies is concentrated in geographic
regions based upon the location of gathering systems and natural gas processing
plants. Although we are one of the largest gatherers and processors in most of
the geographic regions in which we operate, most producers in these areas have
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
the Federal Energy Regulatory Commission ("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 NGL
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 has been regulated under the Natural Gas Act
of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated
thereunder by the 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 the FERC for allocating the
system capacity of "open access" interstate pipelines, at times other system
users can preempt the availability of interstate natural gas transportation and
storage service necessary to enable us to make deliveries and sales of residue
gas. Moreover, shippers and pipelines may negotiate the rates charged by
pipelines for such services within certain allowed parameters. These rates will
also periodically vary depending upon individual system usage and other factors.
An inability to obtain transportation and storage services at competitive rates
can hinder our processing and marketing operations and affect our sales margins.

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

Commencing in April 1992 the 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 users of the pipeline services. The
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 the FERC
continues to review and modify its regulations. For example, the FERC issued
Order No. 637 in February 2000 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 it 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 the 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, transporters, processors and marketers with which
we compete.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the 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 the FERC and Congress will continue.

Gathering. The Natural Gas Act exempts natural gas gathering facilities
from FERC jurisdiction. Interstate natural gas transmission facilities, on the
other hand, remain subject to FERC jurisdiction. The 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
the FERC uses to grant non-jurisdictional gathering facility status. However,
there is no assurance that the 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 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.

In April 2000, the FERC issued Order No. 639, requiring that virtually all
non-proprietary pipeline transporters of natural gas on the outer-continental
shelf report information on their affiliations, rates and conditions of service.
Among the FERC's purposes in issuing these rules was the desire to provide
shippers on the outer-continental shelf with greater assurance of open-access
services on pipelines located on the outer-continental shelf and
non-discriminatory rates and conditions of service on these pipelines. The FERC
exempted Natural Gas Act-regulated pipelines, like that owned and operated by
Dauphin Island Gathering Partners, from the new reporting requirements,
reasoning that the information that these pipelines were already reporting was
sufficient to monitor conformity with existing non-discrimination mandates. The
Company and others challenged the rule, and on January 11, 2002, the U.S.
District Court for the District of Columbia issued a summary judgement in favor
of the Company and the other plaintiffs, and a permanent injunction against the
FERC prohibiting enforcement of Order No. 639. The FERC has filed notice of
appeal to the D.C. Circuit Court of Appeals. A ruling in favor of the FERC could
increase our cost of regulatory compliance and place us at a disadvantage in
comparison to companies that are not required to satisfy the reporting
requirements. Order No. 639 may be altered on appeal, and it is not known at
this time what effect these new rules, as they may be altered, will have on our
business. We currently believe that Order No. 639 and the related reporting
requirements will not have a material adverse effect on our existing business
activities.

Processing. The primary functions of our natural gas processing plants are
the extraction of NGLs and the conditioning of natural gas for marketing. The
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 FERC
jurisdiction.

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

Sales of Natural Gas Liquids. Our sales of NGLs are not currently
regulated and are made at market prices. In a number of instances, however, the
ability to transport and sell such NGLs are dependent on liquids pipelines whose
rates, terms and conditions or service are subject to the Interstate Commerce
Act. Although certain regulations implemented by the FERC in recent years could
result in an increase in the cost of

transporting NGLs on certain petroleum products pipelines, we do not believe
that these regulations affect us any differently than other marketers of NGLs
with whom we compete.

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

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

Canadian Regulation. Our Canadian assets in the province of Alberta are
regulated by the Alberta Energy and Utilities Board. Our assets in the province
of British Columbia are regulated by the B.C. Oil and Gas Commission. Our West
Doe natural gas gathering pipeline and the Pesh Creek natural gas sales line,
which both cross the Alberta/British Columbia border, fall under the
jurisdiction of the National Energy Board of Canada. It is a Group 2 company
which is regulated on a complaint only basis by 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 United States and Canadian laws and regulations at the
federal, state and local levels that relate to air and water quality, hazardous
and solid waste management and disposal, and other environmental matters.
Environmental regulations and laws affecting us include:

- The Clean Air Act and the 1990 amendments to the Act, as well as
counterpart state laws and regulations affecting emissions to the air,
that impose responsibilities on the owners and/or operators of air
emissions sources including obtaining permits and annual compliance and
reporting obligations;

- The Federal Water Pollution Control Act and other amendments, which
require permits for facilities that discharge treated wastewater or other
materials into waters of the United States;

- Federal Solid Waste Disposal Act, as amended by the Resource Conservation
and Recovery Act and its amendments, which regulate the management,
treatment, and disposal of solid and hazardous wastes, and state programs
addressing parallel state issues;

- The Comprehensive Environmental Response, Compensation, and Liability Act
and its amendments, which may impose liability, regardless of fault, for
historic or future disposal or releases of hazardous substances into the
environment, including cleanup obligations associated with such releases
or discharges;

- State regulations for the reporting, assessment and remediation of
releases of material to the environment, including historic releases of
hydrocarbon liquids; and

- Canadian Environmental Laws.

Costs of planning, designing, constructing and operating pipelines, plants,
and other facilities must incorporate compliance with environmental laws and
regulations and safety standards. Failure to comply with these laws and
regulations may trigger a variety of administrative, civil and potentially
criminal enforcement measures, including citizen suits which can include the
assessment of monetary penalties, the imposition of remedial requirements, the
issuance of injunctions or restrictions on operation.

For further discussion of our environmental matters, including possible
liability and capital costs, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Environmental Considerations"
and Note 14, "Commitments and Contingent Liabilities -- Environmental," of the
Notes to Consolidated Financial Statements.

EMPLOYEES

As of December 31, 2001, we had approximately 3,600 employees, which
includes approximately 900 employees of our wholly-owned subsidiary Texas
Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners,
L.P. We are a party to four collective bargaining agreements which cover an
aggregate of approximately 140 of our employees. We believe our relations with
our employees are good.

ITEM 2. PROPERTIES

For information regarding the Company's properties, see "Item 1.
Business -- Natural Gas Gathering, Processing, Transportation, Marketing and
Storage," and "Natural Gas Liquids Transportation, Fractionation and Marketing,"
and "TEPPCO" in this section, each of which is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

See Note 14, "Commitments and Contingent Liabilities," of the Notes to
Consolidated Financial Statements for discussion of the Company's legal
proceedings which is incorporated herein by reference.

Management believes that the resolution of the matters discussed will not
have a material adverse effect on the consolidated results of operations or the
financial position of the Company.

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.

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

No matters were submitted to a vote of the Company's members during the
last quarter of 2001.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Duke Energy beneficially owns 69.7% of our outstanding member interests and
Phillips beneficially owns the remaining 30.3%. There is no market for our
member interests. Unless otherwise approved by our board of directors, we are
prohibited from making any distributions except in an amount sufficient to pay
certain tax obligations of our members that arise from their ownership of member
interests.

In August 2000, we issued $300.0 million of preferred members interests to
affiliates of Duke Energy and Phillips. The proceeds from this financing were
used to repay a portion of our outstanding commercial paper. The preferred
member interests are entitled to cumulative preferential distributions of 9.5%
per annum payable, unless deferred, semiannually. We have the right to defer
payments of preferential distributions on the preferred member interests, other
than certain tax distributions, at any time and from time to time, for up to 10
consecutive semiannual periods. Deferred preferred distributions will accrue
additional amounts based on the preferential distribution rate (plus 0.5% per
annum) to the date of payment. The preferred member interests, together with all
accrued and unpaid preferential distributions, must be redeemed and paid on the
earlier of the thirtieth anniversary date of issuance or consummation of an
initial public offering of the Company's equity securities.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical consolidated financial
and other data for the Company and the Predecessor Company. The selected
historical Annual Income Statement Data, Cash Flow Data and Balance Sheet Data
as of December 31, 2001 and 2000 and for the periods then ended have been
derived from the audited consolidated financial statements of the Company
included elsewhere in this Form 10-K. The selected historical combined financial
data as of December 31, 1999, 1998 and 1997 and for the periods then ended have
been derived from the Predecessor Company's audited historical financial
statements.

The data should be read in conjunction with the financial statements and
related notes and other financial information appearing elsewhere in this Form
10-K.

<Table>
<Caption>
2001 2000(1) 1999(2) 1998 1997
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)

ANNUAL INCOME STATEMENT DATA:
Operating revenues:
Sales of natural gas and petroleum
products........................ $9,315,921 $8,893,515 $3,310,260 $1,469,133 $1,700,029
Transportation, storage and
processing...................... 281,744 199,851 148,050 115,187 101,803
---------- ---------- ---------- ---------- ----------
Total operating revenues...... 9,597,665 9,093,366 3,458,310 1,584,320 1,801,832
Costs and expenses:
Natural gas and petroleum
products........................ 8,313,865 7,875,418 2,965,297 1,338,129 1,468,089
Operating and maintenance.......... 373,477 331,572 181,392 113,556 104,308
Depreciation and amortization...... 278,930 234,862 130,788 75,573 67,701
General and administrative......... 129,968 171,154 73,685 44,946 36,023
Net (gain) loss on sale of
assets.......................... (1,277) (10,660) 2,377 (33,759) (236)
---------- ---------- ---------- ---------- ----------
Total costs and expenses...... 9,094,963 8,602,346 3,353,539 1,538,445 1,675,885
---------- ---------- ---------- ---------- ----------
Operating income..................... 502,702 491,020 104,771 45,875 125,947
Equity in earnings of unconsolidated
affiliates......................... 30,069 27,424 22,502 11,845 9,784
Interest expense..................... 165,670 149,220 52,915 52,403 51,113
---------- ---------- ---------- ---------- ----------
Income before income taxes and
cumulative effect of accounting
change............................. 367,101 369,224 74,358 5,317 84,618
Income tax expense (benefit)......... 2,783 (310,937) 31,029 3,289 33,380
---------- ---------- ---------- ---------- ----------
Net income before cumulative effect
of accounting change............... 364,318 680,161 43,329 2,028 51,238
---------- ---------- ---------- ---------- ----------
Cumulative effect of accounting
change............................. 411 -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income........................... $ 363,907 $ 680,161 $ 43,329 $ 2,028 $ 51,238
========== ========== ========== ========== ==========
</Table>

<Table>
<Caption>
2001 2000(1) 1999(2) 1998 1997
---------- ---------- ----------- ---------- ----------
(IN THOUSANDS, EXCEPT RATIOS AND PER UNIT DATA)

CASH FLOW DATA:
Cash flow from operations......... $ 448,429 $ 713,065 $ 173,136 $ 40,409 $ 173,357
Cash flow from investing
activities..................... (533,847) (234,733) (1,571,446) (203,625) (138,021)
Cash flow from financing
activities..................... 88,771 (477,571) 1,398,934 162,514 (35,061)
</Table>

<Table>
<Caption>
2001 2000(1) 1999(2) 1998 1997
---------- ---------- ----------- ---------- ----------
(IN THOUSANDS, EXCEPT RATIOS AND PER UNIT DATA)

OTHER DATA:
Acquisitions and other capital
expenditures...................... $ 592,630 $ 370,948 $ 1,570,083 $ 185,479 $ 121,978
EBITDA(3)........................... $ 811,701 $ 753,306 $ 258,061 $ 133,293 $ 203,432
Ratio of EBITDA to interest
expense(4)........................ 4.90 5.05 4.88 2.54 3.98
Ratio of earnings to fixed
charges(5)........................ 3.24 3.46 2.33 1.07 2.52
Gas transported and/or processed
(TBtu/d).......................... 8.6 7.6 5.1 3.6 3.4
NGLs production(MBbl/d)............. 397 359 192 110 108
MARKET DATA:
Average NGLs price per gallon(6).... $ .45 $ .53 $ .34 $ .26 $ .35
Average natural gas price per
MMBtu(7).......................... $ 4.27 $ 3.89 $ 2.27 $ 2.11 $ 2.59
BALANCE SHEET DATA (END OF PERIOD):
Total assets........................ $6,630,209 $6,527,997 $ 3,482,296 $1,770,838 $1,649,213
Long term debt...................... $2,235,034 $1,688,157 $ 101,600 $ 101,600 $ 101,600
Preferred members' interest......... $ 300,000 $ 300,000 $ -- $ -- $ --
Members' equity..................... $2,653,042 $2,420,835 (8) (8) (8)
</Table>

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

(1) Includes the results of operations of Phillips' gas gathering, processing,
marketing and NGL business for the nine months ended December 31, 2000.
Phillips' gas gathering, processing, marketing and NGL business was acquired
by the Predecessor Company on March 31, 2000.

(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.
EBITDA is not a measurement presented in accordance with generally accepted
accounting principles. You should not consider this measure in isolation
from or as a substitute for net income or cash flow measures prepared in
accordance with generally accepted accounting principles or as a measure of
our profitability or liquidity. EBITDA is included as a supplemental
disclosure because it may provide useful information regarding our ability
to service debt and to fund capital expenditures. However, not all EBITDA
may be available to service debt. This measure may not be comparable to
similarly titled measures reported by other companies.

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

(5) The ratios of earnings to fixed charges are computed utilizing the
Securities and Exchange Commission ("SEC") guidelines.

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

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

(8) Not applicable due to change in corporate structure as of March 31, 2000.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

Duke Energy Field Services, LLC holds the combined North American midstream
natural gas gathering, processing, marketing and NGL business of Duke Energy and
Phillips Petroleum. The transaction in which those businesses were combined is
referred to as the "Combination."

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

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

The following discussion details the material factors that affected our
historical financial condition and results of operations in 2001, 2000 and 1999.
This discussion should be read in conjunction with "Item 1. Business," and the
consolidated financial statements with the related notes, included elsewhere in
this Form 10-K.

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

OVERVIEW

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

- natural gas gathering, processing, transportation and storage, from which
we generate revenues primarily by providing services such as compression,
treating and gathering, processing, local fractionation, transportation
of residue gas, storage and marketing. In 2001, approximately 56% of the
Company's operating revenues prior to intersegment revenue elimination
and approximately 96% of the 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 2001, approximately 44% prior
to intersegment revenue elimination of the Company's operating revenues
and approximately 4% of the Company's gross margin were from this
segment.

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

EFFECTS OF COMMODITY PRICES

The Company is exposed to commodity prices as a result of being paid for
certain services in the form of commodities rather than cash. For gathering
services, the Company receives fees from the producers to bring the natural gas
from the well head to the processing plant. For processing services, the Company
either receives fees or commodities as payment for these services, depending on
the type of contract. Under a percentage-of-proceeds contract type, the Company
is paid for its services by keeping a percentage of the NGLs produced and the
residue gas resulting from processing the natural gas. Under a keep-whole
contract, the Company keeps a portion of the NGLs produced, but returns the
equivalent Btu content of the gas back to the producer. Based on the Company's
current contract mix, the Company has a long NGL position and is sensitive to
changes in NGL prices. The Company also has a short gas position, however the
short gas position is less significant than the long NGL position.

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 was more heavily
weighted towards arrangements that are commodity price sensitive, approximately
75% of our gross margin is generated by commodity sensitive arrangements and
approximately 25% of our gross margin is generated by fee-based arrangements
during 2001. The commodity exposure is actively managed by the Company as
discussed below.

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 has been generally 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.

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 United States producers, which in turn had a
significant negative effect on natural gas volumes gathered and processed in
1999. Due to reduced supply and strong demand, natural gas and NGL prices
increased throughout 2000 along with renewed strength in drilling activity.

The slowing economy combined with an increase in supply availability
resulting from increased drilling levels drove declines in both crude oil and
natural gas prices during the final two quarters of 2001. NGL prices dramatic
decline is attributed to the decline in crude oil prices in addition to a
decline in the correlation between NGL price and crude oil.

As a result, the weighted average NGL price during 2001 (based on index
prices from the Mont Belvieu and Conway market hubs that are weighted by our
component product and location mix) was approximately $.45 per gallon compared
to $.53 per gallon in 2000 and $.34 per gallon in 1999. During the last two
quarters of 2001, the relationship or correlation between crude oil value and
NGL prices remained depressed. We generally expect NGL prices to follow changes
in crude oil prices over the long term, 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 United
States 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 experienced during 2000 and the first two
quarters of 2001 spurred increased natural gas drilling activity. For example,
the average number of active drilling rigs in North America increased by
approximately 19% from approximately 1,263 in 2000 to 1,497 in 2001. This
drilling activity increase is expected to have a positive effect on natural gas
volumes gathered and processed in the near term. The decline in commodity prices
over the final two quarters of 2001 negatively effected drilling activity as the
average number of active rigs declined to 1,282 during the fourth quarter of
2001. We expect that continued pressure from reduced commodity prices on
drilling will negatively impact North American drilling activity. We expect
lower drilling levels over a sustained period will have a negative effect on
natural gas volumes gathered and processed.

To better address the risks associated with volatile commodity prices, the
Company employs a comprehensive commodity price risk management program. We
closely monitor the risks associated with these commodity price changes on our
future operations and, where appropriate, use various commodity instruments such
as natural gas, crude oil and NGL contracts to hedge the value of our assets and
operations from such price risks. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk." Our 2000 and 2001 results of operations include
a hedging loss of $127.7 million and gain of $6.0 million, respectively. The
hedging loss observed in 2000 relates to hedges placed during periods of
increasing prices. The slight gain recognized in 2001 is the result of a
combination of hedging losses experienced during the first and second quarters,
offset by later gains achieved as a result of a sharp decline in commodity
prices during the third and fourth quarters.

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. During 2001 approximately 65% of our gross margin
from the Natural Gas Segment 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.
During 2001 approximately 20% of our gross margin from the Natural Gas
Segment was generated from fee-based contracts including our general
partnership interest in TEPPCO.

- Keep-Whole Contracts -- Under these contracts we gather raw natural gas
from the producer for processing. After we process the raw natural gas,
we are obligated to return to the producer residue gas with a Btu content
equivalent to the Btu content of the raw natural gas gathered. As a
result of our processing, NGLs are extracted from the raw natural gas
resulting in a shrinkage in the Btu content of the natural gas. We market
the NGLs and purchase natural gas at market prices to return to the
producer residue gas with a Btu content equivalent to the Btu content of
the raw natural gas gathered. Accordingly, under these contracts, we are
exposed to increases in the price of natural gas and decreases in the
price of NGLs. During 2001 approximately 5% of our gross margin from the
Natural Gas Segment was generated from keep-whole contracts.

In addition to the above contracts, during 2001 approximately 10% of the
gross margin from the Natural Gas Segment was generated from condensate sales.

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 changes in natural gas prices.
Our exposure to decreases in NGL prices is partially offset by our hedging
program. Our hedging program reduces the potential negative impact that
commodity price changes could have on our earnings and improves our ability to
adequately plan for cash needed for debt service, dividends, and capital
expenditures. The primary goals of our hedging program include maintaining
minimum cash flows to fund debt service, dividends, production replacement and
maintenance capital projects; avoiding disruption of our growth capital and
value creation process; and retaining a high percentage of potential upside
relating to price increases of NGLs.

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 economic 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 a
variety of contracts to attract certain supply to our systems. 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 Company's portfolio of supply contracts, 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 would result in changes in
annual pre-tax net income of approximately $(25.0) million and $5.0 million,
respectively. After considering the affects of commodity hedge positions in
place at December 31, 2001, it is estimated that if NGL prices average $.01 per
gallon less in the next twelve months pre-tax net income would decrease
approximately $15.0 million. During the first two months of 2002, NGL prices
averaged $.28 per gallon and natural gas prices averaged $2.28 per million Btus
versus the year ending December 31, 2001 average prices of $.45 per gallon and
$4.27 per million Btus respectively.

OTHER FACTORS THAT HAVE SIGNIFICANTLY AFFECTED OUR RESULTS

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

Risk management activities have also affected our results of operations, in
2000 and 2001. Our 2000 and 2001 results of operations include a hedging loss of
$127.7 million and gain of $6.0 million, respectively. See "Item 7A.
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.

HISTORICAL RESULTS OF OPERATIONS

The following is a discussion of our historical results of operations. The
discussion for periods ending on or prior to the Combination on March 31, 2000
relates solely to the Predecessor Company and does not give effect to the
Combination, the transfer to our company of additional midstream natural 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.

<Table>
<Caption>
2001 2000 1999
---------- ---------- ----------
(IN THOUSANDS)

Operating revenues:
Sales of natural gas and petroleum products.... $9,315,921 $8,893,515 $3,310,260
Transportation, storage and processing......... 281,744 199,851 148,050
---------- ---------- ----------
Total operating revenues............... 9,597,665 9,093,366 3,458,310
Purchases of natural gas and petroleum
products.................................... 8,313,865 7,875,418 2,965,297
---------- ---------- ----------
Gross margin..................................... 1,283,800 1,217,948 493,013
Equity earnings of unconsolidated affiliates..... 30,069 27,424 22,502
---------- ---------- ----------
Total gross margin and equity earnings of
unconsolidated affiliates(1)................... $1,313,869 $1,245,372 $ 515,515
========== ========== ==========
</Table>

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

(1) Gross margin and equity in earnings ("Gross Margin") consists of income from
continuing operations before operating and general and administrative
expense, interest expense, income tax expense, and depreciation and
amortization expense plus equity earnings of unconsolidated affiliates.
Gross margin as defined is not a measurement presented in accordance with
generally accepted accounting principles. You should not consider this
measure in isolation from or as a substitute for net income or cash flow
measures prepared in accordance with generally accepted accounting
principles or as an isolated measure of our profitability or liquidity.
Gross margin is included as a supplemental disclosure because it may provide
useful information regarding the impact of key drivers such as commodity
prices and supply contract mix on the Company's earnings.

2001 COMPARED WITH 2000

Gross Margin. Gross Margin increased $68.5 million, or 6% from $1,245.4
million in 2000 to $1,313.9 million in 2001. Of this increase, approximately
$183.0 million was related to the addition of the Phillips' midstream natural
gas business to our operations in the Combination on March 31, 2000. Additional
increases of approximately $28.0 million were attributable to the combination of
our acquisition of Canadian Midstream, Texas intrastate pipelines, northeast
propane terminal and marketing assets, and the acquisition of the general
partnership interest in TEPPCO. These increases were offset by approximately
$130.0 million (net of hedging) due to an $.08 per gallon decrease in average
NGL prices, and approximately $12.0 million due to a $.38 per million Btu
increase in natural gas prices.

The effects of lower NGL prices significantly offset higher gross margin.
Weighted average NGL prices, based on our component product mix, were
approximately $.08 per gallon lower, and natural gas prices were approximately
$.38 per million Btus higher during 2001. These price changes yielded average
prices of $.45 per gallon of NGLs and $4.27 per million Btus of natural gas,
respectively, as compared with $.53 per gallon and $3.89 per million Btus during
2000. Gross margin associated with the natural gas gathering, processing,
transportation, and storage segment increased $62.5 million, or 5%, from
$1,194.8 million to $1,257.3 million, mainly as a result of the Combination.
Commodity sensitive processing arrangements offset this increase by
approximately $130.0 million (net of hedging) due to the $.08 per gallon
decrease in average NGL prices. This reduction was the result of the interaction
of commodity prices and our gas supply arrangements. During the first quarter,
historically high natural gas prices and low fractionation spread caused us to
manage our natural gas price exposure by reducing levels of NGL recovery and
processing volumes where contractual arrangements allowed.

Gross Margin attributable to keep-whole arrangements declined approximately
$90.0 million from approximately $140.0 million in 2000 to $50.0 million in
2001. This decrease is mainly due to the market dynamics present in the first
quarter of 2001. The remainder of decline of gross margin related to NGL price
declines is due to percent-of-proceeds arrangements and condensate sales. These
commodity driven declines

were slightly offset by an increased fee-based activity associated with
acquisitions and processing arrangements.

NGL production during 2001 increased 38,700 barrels per day, or 11%, from
358,500 barrels per day to 397,200 barrels per day, and natural gas transported
and/or processed increased 1.0 trillion Btus per day, or 13%, from 7.6 trillion
Btus per day to 8.6 trillion Btus per day. The primary cause of the increase in
NGL production was the addition of the Phillips' midstream natural gas business
in the Combination offset by reduced recoveries at certain facilities resulting
from tightened fractionation spreads driven by high natural gas prices
experienced during the first two quarters and low NGL prices experienced during
the fourth quarter.

Costs and Expenses. Operating and maintenance expenses increased $41.8
million, or 13%, from $331.6 million in 2000 to $373.4 million in 2001. Of this
increase, approximately $35.6 million is related to the addition of the
Phillips' midstream natural gas business in the Combination. The remainder is
primarily the result of acquisitions offset by plant consolidation and cost
reduction efforts. General and administrative expenses decreased $41.2 million,
or 24%, from $171.2 million in 2000 to $130.0 million in 2001. This decrease is
primarily the result of decreased allocated overhead from our parents, decreased
incentive compensation accruals and focussed cost reduction efforts offset by
the Combination.

Depreciation and amortization increased $44.0 million, or 19%, from $234.9
million in 2000 to $278.9 million in 2001. Of this increase, $21.8 million was
due to the addition of the Phillips' midstream natural gas business in the
Combination. The remainder was due to acquisitions, ongoing capital expenditures
for well connections and facility maintenance/enhancements.

Interest. Interest expense increased $16.5 million, or 11%, from $149.2
million in 2000 to $165.7 million in 2001. This increase was primarily the
result of higher outstanding debt levels, partially offset by lower interest
rates.

Income Taxes. The Company is structured as a limited liability company,
which is a pass-through entity for income tax purposes. As a result of the March
31, 2000 Predecessor Company conversion to a limited liability company,
substantially all of the Predecessor Company's existing net deferred tax
liability ($327.0 million) was eliminated and a corresponding income tax benefit
was recorded. The 2001 income tax expense of $2.8 million is mainly the result
of other miscellaneous taxes.

Net Income. Net income decreased $316.3 million from $680.2 million in
2000 to $363.9 million in 2001. This decrease was largely the result of the tax
benefit recognition discussed above, offset by the addition of the Phillip's
midstream natural gas business in the Combination and cost reduction efforts. A
$6.0 million pre-tax gain from hedging activities experienced during 2001
partially offset the decrease. Lower NGL prices and higher gas prices also
contributed to this decrease.

2000 COMPARED WITH 1999

Gross Margin. Gross Margin increased $729.9 million, or 142% from $515.5
million in 1999 to $1,245.4 million in 2000. Of this increase, approximately
$523.0 million was related to the addition of the Phillips' midstream natural
gas business to our operations in the Combination on March 31, 2000, and
approximately $85.0 million was related to the March 31, 1999 acquisition of
Union Pacific Fuels. The effects of higher NGL prices also contributed
significantly to higher gross margin. Weighted average NGL prices, based on our
component product mix, were approximately $.19 per gallon higher and natural gas
prices were approximately $1.62 per million Btus higher during 2000. These price
increases yielded average prices of $.53 per gallon of NGLs and $3.89 per
million Btus of natural gas, respectively, as compared with $.34 per gallon and
$2.27 per million Btus during 1999.

Gross Margin associated with the natural gas gathering, processing,
transportation, and storage segment increased $714.0 million, or 149%, from
$480.8 million to $1,194.8 million, mainly as a result of the Combination and
the Union Pacific Fuels acquisition. Commodity sensitive processing arrangements
also contributed to this increase by approximately $91.0 million (net of
hedging) due to the $.19 per gallon increase in average NGL prices. Other
factors contributing to the increase were the combination of our acquisition of
the Conoco/Mitchell facilities, Wilcox plant expansion, completion of our Mobile
Bay plant, the

acquisition of Koch's South Texas assets, and the acquisition of the general
partnership interest in TEPPCO. These increases were offset by approximately
$50.0 million due to the $1.62 per million Btus increase in natural gas prices.

Gross Margin attributable to the NGLs fractionation, transportation,
marketing and trading segment increased $15.7 million or 45% from $34.8 million
to $50.5 million. This increase is due primarily to NGL trading and marketing
activity and the acquisition of Union Pacific Fuels.

NGL production during 2000 increased 166,100 barrels per day, or 86%, from
192,400 barrels per day to 358,500 barrels per day, and natural gas transported
and/or processed increased 2.5 trillion Btus per day, or 49%, from 5.1 trillion
Btus per day to 7.6 trillion Btus per day. Of the 166,100 barrels per day
increase in NGL production, the addition of the Phillips' midstream natural gas
business in the Combination contributed approximately 125,800 barrels per day,
and the Union Pacific Fuels acquisition contributed approximately 25,150 barrels
per day. The acquisition of assets from Conoco/Mitchell, our Wilcox plant
expansion, completion of our Mobile Bay Plant and the acquisition of Koch's
South Texas assets accounted for the remainder of the increase. Of the 2.5
trillion Btus per day increase in natural gas transported and/or processed, the
addition of the Phillips' midstream natural gas business in the Combination
contributed approximately 1.6 trillion Btus per day, and the Union Pacific Fuels
acquisition contributed approximately 0.5 trillion Btus per day. The combination
of other acquisitions, plant expansions and completions accounted for the
balance of the increase.

Costs and Expenses. Operating and maintenance expenses increased $150.2
million, or 83%, from $181.4 million in 1999 to $331.6 million in 2000. Of this
increase, approximately $109.3 million is related to the addition of the
Phillips' midstream natural gas business in the Combination and approximately
$13.0 million was related to the Union Pacific Fuels acquisition. General and
administrative expenses increased $97.5 million, or 132%, from $73.7 million in
1999 to $171.2 million in 2000. Of this increase, $12.5 million was due to
increased allocated corporate overhead from Duke Energy as a result of our
company's growth. The remainder was associated with increased activity resulting
from the addition of the Phillips' midstream natural gas business in the
Combination, the Union Pacific Fuels acquisition and increased incentive
compensation accruals for 2000.

Depreciation and amortization increased $104.1 million, or 80%, from $130.8
million in 1999 to $234.9 million in 2000. Of this increase, $72.5 million was
due to the addition of the Phillips' midstream natural gas business in the
Combination and $15.4 million was due to the Union Pacific Fuels acquisition.
The remainder was due to ongoing capital expenditures for well connections,
facility maintenance/enhancements and acquisitions.

Interest. Interest expense increased $96.3 million, or 182%, from $52.9
million in 1999 to $149.2 million in 2000. This increase was primarily the
result of the issuance of commercial paper and the subsequent debt offering in
the third quarter used to repay a portion of the outstanding commercial paper to
fund the distribution paid to Duke Energy and Phillips in the Combination.

Income Taxes. At March 31, 2000, the Predecessor Company converted to a
limited liability company which is a pass-through entity for income tax
purposes. As a result, substantially all of the Predecessor Company's existing
net deferred tax liability ($327.0 million) was eliminated and a corresponding
income tax benefit was recorded.

Net Income. Net income increased $636.9 million from $43.3 million in 1999
to $680.2 million in 2000. This increase was largely the result of the tax
benefit recognition discussed above, the addition of the Phillip's midstream
natural gas business in the Combination and the Union Pacific Fuels acquisition.
Higher NGL prices contributed significantly to this increase but were partially
offset by higher natural gas prices. A $127.7 million pre-tax loss from hedging
activities experienced during 2000 partially offset the increase.

ENVIRONMENTAL CONSIDERATIONS

We have various ongoing remedial matters related to historical operations
similar to others in the industry, based primarily on state authorities
generally described under "Item 1. Business -- Environmental

Matters." 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.

On June 13, 2001, the Company received two administrative Compliance Orders
from the New Mexico Environment Department ("NMED") seeking civil penalties for
primarily historic air permit matters. One order alleges specific permit
non-compliance at 11 facilities that occurred periodically between 1996 and
1999. Allegations under this order relate primarily to emissions from certain
compressor engines in excess of what were then new operating permit limits. The
other order alleges numerous unexcused excursions from an hourly permit limit
arising from upset events at the Company's Dagger Draw facility's sulfur
recovery unit between 1997 and 2001. NMED applied its civil penalty policy to
the alleged violations and calculated the penalties to be $10.4 million in the
aggregate. NMED has initiated settlement discussions and offered to resolve
these matters for an amount lower than the calculated penalties. The Company is
continuing its discussions with NMED and anticipates that it will resolve all
issues relating to the alleged violations.

On September 12, 2001, the Company received a Proposed Agreed Order from
the Texas Natural Resource Conservation Commission ("Commission") to settle
allegations reflected in a June 2001 notice from the Commission relating to the
Company's Port Arthur natural gas processing plant. The Proposed Agreed Order
sought penalties of $278,000 for various items of alleged-noncompliance relating
to the facility's air permit and state air regulations, including valve
monitoring and repair requirements under 40 CFR 60, subpart KKK. The Company has
reached a settlement with the staff of the Commission for a monetary penalty in
the amount of $39,832 and a Supplemental Environmental Project in the amount of
$39,832, subject to the approval of the Commission.

The Company received a Consolidated Compliance Order and Notice of
Potential Penalty from the Louisiana Department of Environmental Quality
("LDEQ") in the spring of 2001 enabling the Company to discharge certain
wastewater streams from its Minden Gas Processing Plant until a new discharge
permit is issued by the LDEQ. The Compliance Order authorized certain
discharges, and otherwise addressed various historic and recent deviations from
Clean Water Act regulatory requirements, including the lapse of the facility's
discharge permit. The Compliance Order also contemplates final resolution of
these matters including the LDEQ issuing a penalty assessment. The Company and
LDEQ are now in discussions to resolve all issues relating to this matter.

The Company is in discussion with the Oklahoma Department of Environmental
Quality ("ODEQ") regarding apparent non-compliance issues relating to the
Company's Title V Clean Air Act Operating permits at its Oklahoma facilities,
primarily consisting of compliance issues disclosed to the ODEQ pursuant to
permit requirements or otherwise voluntarily disclosed to the ODEQ in 2001.
These non-compliance issues relate to various specific and detailed terms of the
Title V permits, including, separate filing requirements, engine testing
procedural requirements, certification requirements, and quarterly emissions
testing obligations. As a result of these discussions, the Company anticipates a
comprehensive settlement agreement will be entered into to resolve these various
items.

We make expenditures in connection with environmental matters as part of
our normal operations and as capital expenses. For each of 2002 and 2003, we
estimate that our expensed and capital-related environmental costs will be
approximately $18.7 million.

LIQUIDITY AND CAPITAL RESOURCES

OPERATING CASH FLOWS

Net cash provided by operations decreased $264.6 million in 2001 from 2000
and increased $539.9 million in 2000 from 1999. The 2001 decrease is primarily
due to a reduction in net income of $316.3 million. The reduction in net income
is largely due to the income tax benefit recorded in 2000. The 2001 decrease is
also due to a reduction in accounts payable, partially offset by a reduction in
accounts receivable. These reductions are due primarily to a lower price
environment in 2001 as compared to 2000.

The increase in cash provided by operations in 2000 as compared to 1999 is
primarily due to an increase in net income of $636.8 million. The increase in
net income is primarily due to the income tax benefit recorded in 2000, the GPM
acquisition in March 2000 and higher commodity prices. The increase is also due
to an increase in accounts payable, partially offset by an increase in accounts
receivable. Price volatility in crude oil, NGLs and natural gas prices have a
direct impact on our use and generation of cash from operations.

INVESTING CASH FLOWS

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
upgrades to our existing facilities. For the year ended December 31, 2001, we
spent approximately $592.6 million on capital expenditures.

On July 10, 2001, the Company acquired additional interests in Mobile Bay
Processing Partners, Gulf Coast NGL Pipeline, L.L.C. and Dauphin Island
Gathering Partners from MCNIC Energy Enterprise Inc. ("MCNIC") for approximately
$66.2 million.

On May 1, 2001, we acquired the outstanding shares of CMSL for a total
purchase price of approximately $162.0 million. The purchase price included the
assumption of debt of approximately $49.3 million.

On April 30, 2001, we acquired in a purchase transaction, Gas Supply
Resources, Inc. ("GSRI"), a propane wholesaler located in the Northeast, for
approximately $45.0 million.

The remaining capital expenditures were primarily for plant expansions,
well connections and plant upgrades.

Our level of capital expenditures for acquisitions and construction depends
on many factors, including industry conditions, the availability of attractive
acquisition opportunities and construction projects, the level of commodity
prices and competition. We expect to finance our capital expenditures with our
cash on hand, cash flow from operations and borrowings available under our
commercial paper program, our credit facilities or other available sources of
financing. Our capital expenditure budget for well connections and plant
upgrades of our existing facilities in 2002 is approximately $200.0 million.

FINANCING CASH FLOWS

Bank Financing and Commercial Paper

In March 2001, we entered into a $675.0 million credit facility ("the
Facility"), of which $150.0 million can be used for letters of credit. The
Facility is used to support our commercial paper program and for working capital
and other general corporate purposes. The Facility matures on March 29, 2002,
however, any outstanding loans under the Facility at maturity may, at our
option, be converted to a one-year term loan. The Facility requires us to
maintain at all times a debt to total capitalization ratio of less than or equal
to 53%. The Facility bears interest at a rate equal to, at our option, either
(1) LIBOR plus 0.75% per year or (2) the higher of (a) the Bank of America prime
rate and (b) the Federal Funds rate plus 0.50% per year. At December 31, 2001,
there were no borrowings against the Facility. The Facility will be replaced by
a new $650.0 million credit facility (the "New Facility"). We expect to close on
the New Facility on March 29, 2002. The New Facility will have substantially the
same terms as the Facility being replaced.

At December 31, 2001 we had a $45.0 million outstanding Irrevocable Standby
Letter of Credit expiring March 29, 2002. This letter of credit was amended to
$30.0 million in January 2002. We plan to extend the expiration of this letter
of credit to March 2003.

At December 31, 2001 we had $213.0 million in outstanding commercial paper,
with maturities ranging from two days to 19 days and annual interest rates
ranging from 7.05% to 7.6%. At no time did the amount of our outstanding
commercial paper exceed the available amount under the Facility. In the future,
our debt levels will vary depending on our liquidity needs, capital expenditures
and cash flow.

Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program and the New 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.

Preferred Financing

In August 2000, we issued $300.0 million of preferred member interests to
affiliates of Duke Energy and Phillips. The proceeds from this financing were
used to repay a portion of our outstanding commercial paper. The preferred
member interests are entitled to cumulative preferential distributions of 9.5%
per annum payable, unless deferred, semiannually. We have the right to defer
payments of preferential distributions on the preferred member interests, other
than certain tax distributions, at any time and from time to time, for up to 10
consecutive semiannual periods. Deferred preferred distributions will accrue
additional amounts based on the preferential distribution rate (plus 0.5% per
annum) to the date of payment. The preferred member interests, together with all
accrued and unpaid preferential distributions, must be redeemed and paid on the
earlier of the thirtieth anniversary date of issuance or consummation of an
initial public offering of equity securities. For the years ending December 31,
2001 and 2000, we have paid preferential distributions of $28.5 million and
$11.7 million, respectively.

Debt Securities

During 2000 and 2001, we registered and issued the following series of
unsecured senior debt securities:

<Table>
<Caption>
PRINCIPAL INTEREST
ISSUE DATE ($000S) RATE DUE DATE
- ---------------------------------------------- --------- -------- -----------------

August 16, 2000............................... $600,000 7 1/2% August 16, 2005
August 16, 2000............................... $800,000 7 7/8% August 16, 2010
August 16, 2000............................... $300,000 8 1/8% August 16, 2030
February 2, 2001.............................. $250,000 6 7/8% February 1, 2011
November 9, 2001.............................. $300,000 5 3/4% November 15, 2006
</Table>

The notes mature and become due and payable on the respective due dates,
and are not subject to any sinking fund provisions. Interest is payable
semiannually. Each series of notes is redeemable, in whole or in part, at our
option. The proceeds from the issuance of debt securities were used to repay a
portion of our outstanding commercial paper.

In October 2001, the Company entered an interest rate swap to convert the
fixed interest rate of $250.0 million of debt securities that were issued in
August 2000 to floating rate debt. The interest rate fair value hedge is at a
floating rate based on 6-month LIBOR rates, which is re-priced semiannually
through 2005. The terms of the swap match the associated debt which permits the
assumption of no ineffectiveness, as defined by Statement of Financial
Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments
and Hedging Activities." As such, for the life of the swap no ineffectiveness
will be recognized. As of December 31, 2001, the fair value of the interest rate
swap of ($4.6) million was included in the Consolidated Balance Sheets as
Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to
the underlying debt included in Long Term Debt.

Distributions

In connection with the Combination, we are required to make quarterly
distributions to Duke Energy and Phillips based on allocated taxable income. Our
Limited Liability Company Agreement provides for taxable income to be allocated
in accordance with the Internal Revenue Code Section 704(c). This Code section
takes into account the variation between the adjusted tax basis and the book
value of assets contributed to the joint venture. The distribution is based on
the highest taxable income allocated to either member, with the

other member receiving a proportionate amount to maintain the ownership capital
accounts at 69.7% for Duke Energy and 30.3% for Phillips. As of December 31,
2001, the distributions based on allocated taxable income payable to the members
were $45.7 million and were paid in January 2002.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

As part of our normal business, we are a party to various financial
guarantees, performance guarantees and other contractual commitments to extend
guarantees of credit and other assistance to various subsidiaries, investees and
other third parties. To varying degrees, these guarantees involve elements of
performance and credit risk, which are not included on the Consolidated Balance
Sheets. The possibility of us having to honor our contingencies is largely
dependent upon future operations of various subsidiaries, investees and other
third parties, or the occurrence of certain future events. We would record a
reserve if events occurred that required that one be established.

At December 31, 2001 we had a $45 million outstanding Irrevocable Standby
Letter of Credit expiring March 29, 2002. This letter of credit was amended to
$30 million in January 2002. We plan to extend the expiration of this letter of
credit to March 2003. In addition, at December 31, 2001 we are the guarantor of
approximately $28.9 million of debt associated with an unconsolidated
subsidiary. Assets of the unconsolidated subsidiary are pledged as collateral
for the debt.

ACCOUNTING PRONOUNCEMENTS

On January 1, 2001, the Company adopted SFAS No. 133. In accordance with
the transition provisions of SFAS No. 133, the Company recorded a
cumulative-effect adjustment of $0.4 million as a reduction in earnings and a
cumulative-effect adjustment increasing Other Comprehensive Income ("OCI") and
member's equity by $6.6 million.

In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets."

SFAS No. 141 requires all business combinations initiated (as defined by
the standard) after June 30, 2001 to be accounted for using the purchase method.
Companies may no longer use the pooling method for future combinations.

SFAS No. 142 is effective for fiscal years beginning after December 15,
2001 and was adopted by the Company as of January 1, 2002. SFAS No. 142 requires
that goodwill no longer be amortized over an estimated useful life, as
previously required. Instead, goodwill amounts will be subject to a
fair-value-based annual impairment assessment. The standard also requires
acquired intangible assets to be recognized separately and amortized as
appropriate. No such intangibles have been identified at the Company. We expect
the adoption of SFAS No. 142 to have an impact on future financial statements,
due to the discontinuation of goodwill amortization expense. For 2001, goodwill
amortization expense was $22.0 million. We have evaluated the fair value
evidence and have concluded that there is no impairment of goodwill as of
January 1, 2002.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements for
retirement obligations associated with tangible long-lived assets. It is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. We are currently assessing the new standard and have not yet
determined the impact on our consolidated results of operations, cash flows or
financial position.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." The new rules supersede SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." The new rules retain many of the fundamental
recognition and measurement provisions of SFAS No. 121, but significantly change
the criteria for classifying an asset as held-for-sale. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001. We have evaluated
the new standard and believe that it will have no material effect on our
consolidated results of operations or financial position.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

RISK AND ACCOUNTING POLICIES

We are exposed to market risks associated with commodity prices, credit
exposure, interest rates and foreign currency exchange rates. Management has
established comprehensive risk management policies to monitor and manage these
market risks. Our Risk Management Committee ("RMC") oversees risk exposure
including fluctuations in commodity prices. The RMC ensures that proper policies
and procedures are in place to adequately manage our commodity price risks and
is responsible for the overall management of commodity price and other risk
exposures.

Mark-to-Market Accounting ("MTM accounting") -- Under the MTM accounting
method, an asset or liability is recognized at fair value and the change in the
fair value of that asset or liability is recognized in earnings during the
current period. This accounting method has been used by other industries for
many years, and in 1998 the FASB's Emerging Issues Task Force ("EITF") issued
guidance 98-10 that required MTM accounting for energy trading contracts. MTM
accounting reports contracts at their "fair value," (the value a willing third
party would pay for the particular contract at the time a valuation is made).

When available, quoted market prices are used to record a contract's fair
value. However, market values for energy trading contracts are often not easy to
determine because the duration of the contracts may exceed the liquid activity
in a particular market. If no active trading market exists for a commodity or
for a contract's duration, holders of these contracts must calculate fair value
using pricing models or matrix pricing based on contracts with similar terms and
risks. This is validated by a group independent of the Company's trading area.
Holders of thinly-traded securities or investments (mutual funds, for example)
use similar techniques to price such holdings. Correlation and volatility are
two significant factors used in the computation of fair values. We validate our
internally developed fair values by comparing locations/tenors that are highly
correlated, using forecasted market intelligence and mathematical extrapolation
techniques. While we use industry best practices to develop our pricing models,
changes in our pricing methodologies or the assumptions therein could result in
significantly different fair values and realization in future periods.

Hedge Accounting -- Hedge accounting typically refers to the mechanism that
the Company uses to minimize losses caused by price fluctuations. Hedge
accounting treatment is used when we contract to buy or sell a commodity such as
natural gas at a fixed price for future delivery corresponding with the
anticipated physical sale or purchase of natural gas (cash flow hedge). In
addition, hedge accounting treatment is used when the Company holds firm
commitments or asset positions, and enters into transactions that "hedge" our
risk that the price of natural gas may change between the contract's inception
and the physical delivery date of the commodity (fair value hedge). The majority
of our hedging transactions are used to protect the value of future cash flows
related to physical assets. To the extent the hedge is effective, we recognize
in earnings the value of the contract when the commodity is purchased or sold,
or the hedged transaction occurs or settles.

COMMODITY PRICE RISK

We are exposed to the impact of market fluctuations primarily in the price
of NGLs that we own as a result of our processing activities. We employ
established policies and procedures to manage our risks associated with these
market fluctuations using various commodity derivatives, including forward
contracts, swaps and options for non-trading activity (primarily hedge
strategies). (See Notes 2 and 12 to the Consolidated Financial Statements.)

Commodity Derivatives -- Trading -- The risk in the commodity trading
portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk
model to determine the potential one-day favorable or unfavorable Daily Earnings
at Risk ("DER"). DER is monitored daily in comparison to established thresholds.
Other measures are also used to limit and monitor the risk in the commodity
trading portfolio (which includes all trading contracts not designated as hedge
positions) on a monthly and annual basis. These measures include limits on the
nominal size of positions and periodic loss limits.

DER computations are based on a historical simulation, which uses price
movements over a specified period (generally ranging from seven to 14 days) to
simulate forward price curves in the energy markets to

estimate the potential favorable or unfavorable impact of one day's price
movement on the existing portfolio. The historical simulation emphasizes the
most recent market activity, which is considered the most relevant predictor of
immediate future market movements for crude, NGLs, gas and other energy-related
products. DER computations utilize several key assumptions, including 95%
confidence level for the resultant price movement and the holding period
specified for the calculation. The Company's DER amounts for commodity
derivatives instruments held for trading purposes are shown in the following
table.

DAILY EARNINGS AT RISK

<Table>
<Caption>
ESTIMATED AVERAGE ESTIMATED AVERAGE HIGH ONE-DAY LOW ONE-DAY
ONE-DAY IMPACT ONE-DAY IMPACT IMPACT ON EBIT IMPACT ON EBIT
ON EBIT FOR 2001 ON EBIT FOR 2000 FOR 2001 FOR 2001
----------------- ----------------- -------------- --------------
(IN MILLIONS)

Calculated DER................... $1.7 $1.2 $5.7 $0.4
</Table>

DER is an estimate based on historical price volatility. Actual volatility
can exceed predicted results. DER also assumes a normal distribution of price
changes, thus if the actual distribution is not normal, the DER may understate
or overstate actual results. DER is used to estimate the risk of the entire
portfolio, and for locations that do not have daily trading activity, it may not
accurately estimate risk due to limited price information. Stress tests may be
employed in addition to DER to measure risk where market data information is
limited. In the current DER methodology, options are modeled in a manner
equivalent to forward contracts which may understate the risk.

Our exposure to commodity price risk is influenced by a number of factors,
including contract size, length of contract, market liquidity, location and
unique or specific contract terms. The following table illustrates the movements
in the fair value of our trading instruments during 2001.

CHANGES IN FAIR VALUE OF TRADING CONTRACTS

<Table>
<Caption>
(IN MILLIONS)

Fair value of contracts outstanding at the beginning of the
year...................................................... $ (5.0)
SFAS No. 133 reclassification adjustment.................... (14.1)
Contracts realized or otherwise settled during the year..... (1.6)
Net mark-to-market changes in fair values................... 58.1
------
Fair value of contracts outstanding at the end of the
year...................................................... $ 37.4
======
</Table>

For the year ended December 31, 2001, the unrealized net margin recognized
in operating income was $42.4 million as compared to ($5.4) million for 2000 and
$0.4 million for 1999. The fair value of these contracts is expected to be
realized in future periods, as detailed in the following table. The amount of
cash ultimately realized for these contracts will differ from the amounts shown
in the following table due to factors such as market volatility, counterparty
default and other unforeseen events that could impact the amount and/or
realization of these values. At December 31, 2001, we held cash or letters of
credit of $3.3 million to secure such future performance, and had no amounts
deposited with counterparties.

When available, we use observable market prices for valuing our trading
instruments. When quoted market prices are not available, we use established
guidelines for the valuation of these contracts. We may use a variety of
reasonable methods to assist in determining the valuation of a financial
instrument, including analogy to reliable quotations of similar financial
instruments, pricing models, matrix pricing and other formula-based pricing
methods. These methodologies incorporate factors for which published market data
may be available. All valuation methods employed by us are approved by an
internal corporate risk management organization independent of the trading
function and are applied on a consistent basis.

The following table shows the fair value of our trading portfolio as of
December 31, 2001.

<Table>
<Caption>
FAIR VALUE OF CONTRACTS AS OF DECEMBER 31, 2001
------------------------------------------------------------------------
MATURITY IN
MATURITY IN MATURITY IN MATURITY IN 2005 AND
SOURCES OF FAIR VALUE 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE
- --------------------- ----------- ----------- ----------- ----------- ----------------
(IN MILLIONS)

Prices supported by
quoted market prices
and other external
sources................ $27.1 $1.0 $ 0.7 $ -- $28.8
----- ---- ----- ---- -----
Prices based on models
and other valuation
methods................ 10.8 1.2 (3.6) 0.2 8.6
----- ---- ----- ---- -----
Total.......... $37.9 $2.2 $(2.9) $0.2 $37.4
===== ==== ===== ==== =====
</Table>

The "prices supported by quoted market prices and other external sources"
category includes Duke Energy Field Services' New York Mercantile Exchange
("NYMEX") swap positions in natural gas and crude oil. The NYMEX has currently
quoted prices for the next 32 months. In addition, this category includes our
forward positions and options in natural gas and natural gas basis swaps at
points for which over-the-counter ("OTC") broker quotes are available. On
average, OTC quotes for natural gas forwards and swaps extend 22 and 32 months
into the future, respectively. OTC quotes for natural gas options extend 12
months into the future, on average. We value these positions against internally
developed forward market price curves that are constantly validated and
recalibrated against OTC broker quotes. This category also includes "strip"
transactions whose prices are obtained from external sources and then modeled to
daily or monthly prices as appropriate.

The "prices based on models and other valuation methods" category includes
(i) the value of options not quoted by an exchange or OTC broker, (ii) the value
of transactions for which an internally developed price curve was constructed as
a result of the long dated nature of the transaction or the illiquidity of the
market point, and (iii) the value of structured transactions. It is important to
understand that in certain instances structured transactions can be decomposed
and modeled by us as simple forwards and options based on prices actively
quoted. Although the valuation of the simple structures might not be different
from the valuation of contracts in other categories, the effective model price
for any given period is a combination of prices from two or more different
instruments and therefore have been included in this category due to the complex
nature of these transactions.

Hedging Strategies -- We are exposed to market fluctuations in the prices
of energy commodities related to natural gas gathering, processing and marketing
activities. We closely monitor the risks associated with these commodity price
changes on our future operations and, where appropriate, use various commodity
instruments such as natural gas, crude oil and NGL contracts to hedge the value
of our assets and operations from such price risks. Our primary use of commodity
derivatives is to hedge the output and production of assets we physically own.
Contract terms are up to four years, however, since these contracts are
designated and qualify as effective hedge positions of future cash flows, or
fair values of assets owned by us, to the extent that the hedge relationships
are effective, their market value change impacts are not recognized in current
earnings. The unrealized gains or losses on these contracts are deferred in OCI
or included in Other Current or Noncurrent Assets or Liabilities on the
Consolidated Balance Sheets, in accordance with SFAS No. 133. Amounts deferred
in OCI are realized in earnings concurrently with the transaction being hedged.
(See Notes 2 and 12 to the Consolidated Financial Statements.) However, in
instances where the hedging contract no longer qualifies for hedge accounting,
amounts included in OCI through the date of de-designation remain in OCI until
the underlying transaction actually occurs. The derivative contract (if
continued as an open position) will be marked to market currently through
earnings. Several factors influence the effectiveness of a hedge contract,
including counterparty credit.

The following table shows when gains and losses deferred on the
Consolidated Balance Sheets for derivative instruments qualifying as effective
hedges of firm commitments or anticipated future transactions will be recognized
into earnings. Contracts with terms extending several years are generally valued
using

models and assumptions developed internally or by industry standards. However,
as mentioned previously, the effective portion of the gains and losses for these
contracts are not recognized in earnings until settlement at their then market
price. Therefore, assumptions and valuation techniques for these contracts have
no impact on reported earnings prior to settlement for the effective portion of
these hedges.

The fair value of our qualifying hedge positions at a point in time is not
necessarily indicative of the results realized when such contracts settle.

<Table>
<Caption>
CONTRACT VALUE AS OF DECEMBER 31, 2001
------------------------------------------------------------------
MATURITY IN
MATURITY IN MATURITY IN MATURITY IN 2005 AND TOTAL FAIR
SOURCES OF FAIR VALUE 2002 2003 2004 THEREAFTER VALUE
- --------------------- ----------- ----------- ----------- ----------- ----------
(IN MILLIONS)

Quoted market prices........... $27.6 $3.5 $ -- $ -- $31.1
----- ---- ----- ----- -----
Prices based on models or other
valuation techniques......... 26.0 -- -- -- 26.0
----- ---- ----- ----- -----
Total................ $53.6 $3.5 $ -- $ -- $57.1
===== ==== ===== ===== =====
</Table>

Based upon our portfolio of supply contracts, 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 would result in changes in annual pre-tax net
income of approximately ($25.0) million and $5.0 million, respectively. After
considering the affects of commodity hedge positions in place at December 31,
2001, it is estimated that if NGL prices average $.01 per gallon less in the
next twelve months, pre-tax net income would decrease approximately $15.0
million. Comparatively, the same sensitivity analysis as of December 31, 2000
estimated that pre-tax net income would decrease approximately $20.0 million in
2001. The hedge contracts are intended to mitigate the impact that price changes
have on our physical positions. During the first two months of 2002, NGL prices
averaged $.28 per gallon and natural gas prices averaged $2.28 per million Btus
versus the year ending December 31, 2001 average prices of $.45 per gallon and
$4.27 per million Btus respectively.

CREDIT RISK

We sell natural gas liquids 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 NGL production that is
committed to Phillips and Chevron Phillips Chemical LLC, under an existing
15-year contract, of which 13 years remain. This concentration of credit risk
may affect our overall credit risk in that these customers may be similarly
affected by changes in economic, regulatory or other factors. On all
transactions where we are exposed to credit risk, we analyse the counterparties'
financial condition prior to entering into an agreement, establish credit limits
and monitor the appropriateness of these limits on an ongoing basis. The
corporate credit policy prescribes the use of master collateral agreements to
mitigate credit exposure. The collateral agreements provide for a counterparty
to post cash or letters of credit for exposure in excess of the established
threshold. The threshold amount represents an open credit limit, determined in
accordance with the corporate credit policy. The collateral agreements also
provide that the inability to post collateral is sufficient cause to terminate a
contract and liquidate all positions.

Physical forward contracts and financial derivatives are generally cash
settled at the expiration of the contract term. However, these transactions are
generally subject to margin agreements with the majority of our counterparties.

Following the bankruptcy of Enron Corporation, we have terminated
substantially all contracts with Enron Corporation and its affiliated companies
(collectively, "Enron"). As a result, we recorded in 2001, as a charge, a
non-collateralized accounting exposure of $2.7 million. The transactions between
Enron and the Company consisted of physical purchase/sale contracts for natural
gas and NGLs, forward contracts, swaps and options used to trade natural gas and
NGLs, and transportation and storage transactions.

The $2.7 million charge was a direct reduction to earnings before income
taxes and was a result of charging the full amount of unsettled mark-to-market
earnings previously recognized, and all derivative assets and accounts
receivable that became impaired due to Enron's condition.

Our determination of the bankruptcy claims against Enron is still under
review, and the claims made in the bankruptcy case are likely to exceed $2.7
million. Any bankruptcy claims that exceed this amount would primarily relate to
termination and settlement rights under contracts and transactions with Enron
that would have been recognized in future periods and not in the historical
periods covered by the financial statements to which the $2.7 million charge
relates. Substantially all contracts with Enron were completed or terminated
prior to December 31, 2001.

INTEREST RATE RISK

We enter into debt arrangements that are exposed to market risks related to
changes in interest rates. We periodically utilize interest rate lock agreements
and interest rate swaps to hedge interest rate risk associated with new debt
issuances. Our primary goals include (1) maintaining an appropriate ratio of
fixed-rate debt to total debt for the Company's debt rating; (2) reducing
volatility of earnings resulting from interest rate fluctuations; and (3)
locking in attractive interest rates based on historical averages. As of
December 31, 2001, the fair value of our interest rate swap was a liability of
$4.6 million. (See Notes 2 and 12 to the Consolidated Financial Statements.)

As of December 31, 2001, we had approximately $213.0 million 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. An
increase of .5% in interest rates would result in an increase in annual interest
expense of approximately $2.3 million.

FOREIGN CURRENCY RISK

Our primary foreign currency exchange rate exposure at December 31, 2001
was the Canadian dollar. Foreign currency risk associated with this exposure was
not material.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999

<Table>
<Caption>
2001 2000 1999
---------- ---------- ----------
(IN THOUSANDS)

OPERATING REVENUES:
Sales of natural gas and petroleum products............ $6,851,265 $6,787,599 $2,613,560
Sales of natural gas and petroleum
products -- affiliates.............................. 2,464,656 2,105,916 696,700
Transportation, storage and processing................. 281,744 188,501 138,151
Transportation, storage and processing -- affiliates... -- 11,350 9,899
---------- ---------- ----------
Total operating revenues....................... 9,597,665 9,093,366 3,458,310
---------- ---------- ----------
COSTS AND EXPENSES:
Purchases of natural gas and petroleum products........ 7,495,229 7,114,070 2,836,697
Purchases of natural gas and petroleum
products -- affiliates.............................. 818,636 761,348 128,600
Operating and maintenance.............................. 373,477 331,572 181,392
Depreciation and amortization.......................... 278,930 234,862 130,788
General and administrative............................. 118,249 140,557 54,585
General and administrative -- affiliates............... 11,719 30,597 19,100
Net (gain) loss on sale of assets...................... (1,277) (10,660) 2,377
---------- ---------- ----------
Total costs and expenses....................... 9,094,963 8,602,346 3,353,539
---------- ---------- ----------
OPERATING INCOME......................................... 502,702 491,020 104,771
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES.......... 30,069 27,424 22,502
INTEREST EXPENSE:
Interest expense (income).............................. 165,670 134,016 (985)
Interest expense -- affiliates......................... -- 15,204 53,900
---------- ---------- ----------
Total interest expense......................... 165,670 149,220 52,915
---------- ---------- ----------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE............................ 367,101 369,224 74,358
INCOME TAX EXPENSE (BENEFIT)............................. 2,783 (310,937) 31,029
---------- ---------- ----------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE...................................... 364,318 680,161 43,329
CUMULATIVE EFFECT OF ACCOUNTING CHANGE................... 411 -- --
---------- ---------- ----------
NET INCOME............................................... 363,907 680,161 43,329
DIVIDENDS ON PREFERRED MEMBERS' INTEREST................. 28,500 11,717 --
---------- ---------- ----------
EARNINGS AVAILABLE FOR MEMBERS' INTEREST................. $ 335,407 $ 668,444 $ 43,329
========== ========== ==========
</Table>

See Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999

<Table>
<Caption>
2001 2000 1999
-------- -------- -------
(IN THOUSANDS)

NET INCOME.................................................. $363,907 $680,161 $43,329
OTHER COMPREHENSIVE INCOME (LOSS):
Cumulative effect of change in accounting principle....... 6,626 -- --
Foreign currency translation adjustment................... (4,460) (2,717) 288
Net unrealized gains on cash flow hedges.................. 51,621 -- --
Reclassification into earnings............................ (3,313) -- --
-------- -------- -------
Total other comprehensive income (loss)........... 50,474 (2,717) 288
-------- -------- -------
TOTAL COMPREHENSIVE INCOME.................................. $414,381 $677,444 $43,617
======== ======== =======
</Table>

See Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999

<Table>
<Caption>
2001 2000 1999
--------- ----------- -----------
(IN THOUSANDS)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 363,907 $ 680,161 $ 43,329
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 278,930 234,862 130,788
Deferred income taxes (benefit)......................... 2,783 (308,001) 86,301
Change in fair value of derivative instruments.......... 2,066 -- --
Equity in earnings of unconsolidated affiliates......... (30,069) (27,424) (22,502)
Net (gain) loss on sale of assets....................... (1,277) (10,660) 2,377
Change in operating assets and liabilities (net of effects
of acquisitions) which provided (used) cash:
Accounts receivable..................................... 533,109 (492,475) (168,806)
Accounts receivable -- affiliates....................... 22,756 (189,300) (6,202)
Inventories............................................. 9,856 (73,348) (5,303)
Unrealized gains on mark-to-market transactions......... (88,842) (35,724) (10,461)
Other current assets.................................... 1,013 41,324 20,356
Other noncurrent assets................................. (590) (9,414) --
Accounts payable........................................ (633,599) 808,980 101,309
Accounts payable -- affiliates.......................... (35,844) (906) 51,608
Accrued interest payable................................ 7,807 49,641 --
Unrealized losses on mark-to-market transactions........ 46,811 41,100 10,079
Other current liabilities............................... (7,647) 51,036 (4,390)
Other long term liabilities............................. (22,741) (46,787) (55,347)
--------- ----------- -----------
Net cash provided by operating activities.......... 448,429 713,065 173,136
--------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for acquisitions............................. (220,097) (163,565) (1,404,354)
Other capital expenditures................................ (372,533) (207,383) (165,729)
Investment expenditures................................... (4,795) (5,323) (62,752)
Investment distributions.................................. 41,278 43,557 31,999
Proceeds from sales of assets............................. 22,300 97,981 29,390
--------- ----------- -----------
Net cash used in investing activities.............. (533,847) (234,733) (1,571,446)
--------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net (decrease) increase in advances -- members............ (11,347) (55,509) 1,350,054
Distributions to members.................................. (235,564) (2,744,319) --
Proceeds from issuing preferred members' interest......... -- 300,000 --
Short term debt -- net.................................... (133,455) 346,410 --
Proceeds from issuing debt -- net......................... 546,918 1,687,564 48,880
Payment of debt........................................... (49,281) -- --
Payment of dividends...................................... (28,500) (11,717) --
--------- ----------- -----------
Net cash provided by (used in) financing
activities....................................... 88,771 (477,571) 1,398,934
--------- ----------- -----------
NET INCREASE IN CASH........................................ 3,353 761 624
CASH, BEGINNING OF YEAR..................................... 1,553 792 168
--------- ----------- -----------
CASH, END OF YEAR........................................... $ 4,906 $ 1,553 $ 792
========= =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION -- Cash
paid for interest (net of amounts capitalized)............ $ 155,946 $ 95,805 $ 52,915
</Table>

See Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2001 AND 2000

<Table>
<Caption>
2001 2000
---------- ----------
(IN THOUSANDS)

ASSETS

CURRENT ASSETS:
Cash...................................................... $ 4,906 $ 1,553
Accounts receivable:
Customers, net.......................................... 520,118 1,080,083
Affiliates.............................................. 230,521 253,277
Other................................................... 136,810 67,316
Inventories............................................... 82,935 86,520
Unrealized gains on trading and hedging transactions...... 180,809 46,185
Other..................................................... 9,060 14,275
---------- ----------
Total current assets............................... 1,165,159 1,549,209
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 4,711,960 4,152,480
INVESTMENT IN AFFILIATES.................................... 132,252 261,551
INTANGIBLE ASSETS:
Natural gas liquids sales and purchases contracts, net.... 94,019 97,956
Goodwill, net............................................. 421,176 376,195
---------- ----------
Total intangible assets............................ 515,195 474,151
---------- ----------
UNREALIZED GAINS ON TRADING AND HEDGING
TRANSACTIONS.............................................. 19,095 --
OTHER NONCURRENT ASSETS..................................... 86,548 90,606
---------- ----------
TOTAL ASSETS....................................... $6,630,209 $6,527,997
========== ==========

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade................................................... $ 620,094 $1,273,029
Affiliates.............................................. 25,620 61,464
Other................................................... 76,914 41,322
Short term debt........................................... 212,955 346,410
Accrued taxes other than income........................... 24,646 21,717
Distributions payable to members.......................... 45,672 127,561
Accrued interest payable.................................. 57,417 49,641
Unrealized losses on trading and hedging transactions..... 84,811 51,179
Other..................................................... 102,694 114,408
---------- ----------
Total current liabilities.......................... 1,250,823 2,086,731
---------- ----------
DEFERRED INCOME TAXES....................................... 14,362 --
LONG TERM DEBT.............................................. 2,235,034 1,688,157
UNREALIZED LOSSES ON TRADING AND
HEDGING TRANSACTIONS...................................... 25,188 --
OTHER LONG TERM LIABILITIES................................. 15,845 32,274
MINORITY INTERESTS.......................................... 135,915 --
PREFERRED MEMBERS' INTEREST................................. 300,000 300,000
COMMITMENTS AND CONTINGENT LIABILITIES
MEMBERS' EQUITY:
Members' interest......................................... 1,709,290 1,709,290
Retained earnings......................................... 895,707 713,974
Accumulated other comprehensive income (loss)............. 48,045 (2,429)
---------- ----------
Total members' equity.............................. 2,653,042 2,420,835
---------- ----------
TOTAL LIABILITIES AND MEMBERS' EQUITY....................... $6,630,209 $6,527,997
========== ==========
</Table>

See Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999

<Table>
<Caption>
ACCUMULATED
ADDITIONAL OTHER
COMMON PAID-IN MEMBERS' RETAINED COMPREHENSIVE
STOCK CAPITAL INTEREST EARNINGS INCOME (LOSS) TOTAL
------ ---------- ----------- --------- ------------- -----------
(IN THOUSANDS)

BALANCE, JANUARY 1, 1999...... $ 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
Combination at March 31,
2000 -- see Note 2:
Contribution of TEPPCO
general partnership
interest.................. -- 2,148 -- -- -- 2,148
Contribution of DEFS Inc.
and DEFSCL to DEFS, LLC... (1) (215,239) 215,240 -- -- --
Contribution of notes and
advances payable.......... -- -- 2,318,569 -- -- 2,318,569
Contribution of GPM assets
and liabilities........... -- -- 1,919,800 -- -- 1,919,800
Distributions............... -- -- (2,744,319) (127,561) -- (2,871,880)
Dividends on preferred
members' interest........... -- -- -- (11,717) -- (11,717)
Net Income.................... -- -- -- 680,161 -- 680,161
Other......................... -- -- -- -- (2,717) (2,717)
----- --------- ----------- --------- ------- -----------
BALANCE, DECEMBER 31, 2000.... -- -- 1,709,290 713,974 (2,429) 2,420,835
Distributions................. -- -- -- (153,674) -- (153,674)
Dividends on preferred
members' interest........... -- -- -- (28,500) -- (28,500)
Net Income.................... -- -- -- 363,907 -- 363,907
Other......................... -- -- -- -- 50,474 50,474
----- --------- ----------- --------- ------- -----------
BALANCE, DECEMBER 31, 2001.... $ -- $ -- $ 1,709,290 $ 895,707 $48,045 $ 2,653,042
===== ========= =========== ========= ======= ===========
</Table>

See Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999

1. GENERAL

Basis of Presentation -- Duke Energy Field Services, LLC (with its
consolidated subsidiaries, "the Company" or "Field Services LLC") operates in
the midstream natural gas gathering, marketing and natural gas liquids
industries. The Company operates in the two principal segments of the midstream
natural gas industry of (1) natural gas gathering, processing, transportation,
marketing and storage; and (2) natural gas liquids ("NGLs") fractionation,
transportation, marketing and trading. Field Services LLC's limited liability
company agreement limits the scope of the Company's business to the midstream
natural gas industry in the United States and Canada, the marketing of natural
gas liquids in Mexico and the transportation, marketing and storage of other
petroleum products.

The Company is the successor to Duke Energy Corporation's ("Duke Energy")
North American midstream natural gas business. The subsidiaries of Duke Energy
that conducted this business were contributed to the Company immediately prior
to the Combination (see Note 3). For periods prior to the Combination, Duke
Energy Field Services and these subsidiaries of Duke Energy are collectively
referred to herein as the "Predecessor Company."

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation -- The Consolidated Financial Statements include the accounts
of the Company and all majority-owned subsidiaries, after eliminating
significant intercompany transactions and balances. Investments in 20% to 50%
owned affiliates are accounted for using the equity method. Investments greater
than 50% are consolidated unless the Company does not operate these investments
and as a result does not have the ability to exercise control (see Note 9).

Use of Estimates -- Conformity with accounting principles generally
accepted in the United States of America requires management to make estimates
and assumptions that affect the amounts reported in the financial statements and
notes. Although these estimates are based on management's best available
knowledge of current and expected future events, actual results could be
different from those estimates.

Inventories -- Inventories consist primarily of materials and supplies and
natural gas and NGLs held in storage for transmission and processing and sales
commitments. Inventories are recorded at the lower of cost or market value using
the average cost method (see Note 7). Natural gas storage arbitrage volumes are
marked to market.

Accounting for Hedges and Commodity Trading Activities -- All derivatives
are recorded in the Consolidated Balance Sheets at their fair value as
Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. On
the date that swaps or option contracts are entered into, the Company designates
the derivative as either held for trading (trading instruments); as a hedge of a
recognized asset, liability or firm commitment (fair value hedges); as a hedge
of a forecasted transaction or future cash flows (cash flow hedges); or leaves
the derivative undesignated and marks it to market.

For hedge contracts, the Company formally assesses, both at the hedge
contracts inception and on an ongoing basis, whether the hedge contract is
highly effective in offsetting changes in fair values or cash flows of hedged
items. The Company currently excludes the time value of the options when
assessing hedge effectiveness.

When available, quoted market prices or prices obtained through external
sources are used to verify a contract's fair value. For contracts with a
delivery location or duration for which quoted market prices are not available,
fair value is determined based on pricing models developed primarily from
historical and expected correlations with quoted market prices.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Values are adjusted to reflect the potential impact of liquidating the
positions held in an orderly manner over a reasonable time period under current
conditions. Changes in market price and management estimates directly affect the
estimated fair value of these contracts. Accordingly, it is reasonably possible
that such estimates may change in the near term.

Commodity Trading -- A favorable or unfavorable price movement of any
derivative contract held for trading purposes is reported as Purchases of
Natural Gas and Petroleum Products in the Consolidated Statements of Income. An
offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized
Gains or Unrealized Losses on Trading and Hedging Transactions. When a contract
to sell is physically settled, the fair value entries are reversed and the gross
amount invoiced to the customer is included as Sales of Natural Gas and
Petroleum Products in the Consolidated Statements of Income. Similarly, when a
contract to purchase is physically settled, the purchase price is included as
Purchases of Natural Gas and Petroleum Products in the Consolidated Statements
of Income. If a contract is not physically settled, the unrealized gain or
unrealized loss in the Consolidated Balance Sheets is reclassified to a
receivable or payable account. For income statement purposes, financial
settlement has no net operating income presentation effect on the Consolidated
Statements of Income.

Commodity Cash Flow Hedges -- Changes in fair value of a derivative
designated and qualified as a cash flow hedge are included in the Consolidated
Statements of Comprehensive Income as Other Comprehensive Income ("OCI") until
earnings are affected by the hedged item. Settlement amounts and ineffective
portions of cash flow hedges are removed from OCI and recorded in the
Consolidated Statements of Income in the same accounts as the item being hedged.
The Company discontinues hedge accounting prospectively when it is determined
that the derivative no longer qualifies as an effective hedge, or when it is no
longer probable that the hedged transaction will occur. When hedge accounting is
discontinued because the derivative no longer qualifies as an effective hedge,
the derivative continues to be carried on the Consolidated Balance Sheets at its
fair value, with subsequent changes in its fair value recognized in
current-period earnings. Gains and losses related to discontinued hedges that
were previously accumulated in OCI will remain in OCI until earnings are
affected by the hedged item, unless it is no longer probable that the hedged
transaction will occur. Gains and losses that were accumulated in OCI will be
immediately recognized in current-period earnings.

Commodity Fair Value Hedges -- Changes in the fair value of a derivative
that is designated and qualifies as a fair value hedge are included in the
Consolidated Statements of Income as Sales of Natural Gas and Petroleum Products
and Purchases of Natural Gas and Petroleum Products, as appropriate. Changes in
the fair value of the physical portion of a fair value hedge (i.e., the hedged
item) are recorded in the Consolidated Statements of Income in the same accounts
as the changes in the fair value of the derivative, with offsetting amounts in
the Consolidated Balance Sheets as Other Current Assets, Other Noncurrent
Assets, Other Current Liabilities, or Other Long Term Liabilities, as
appropriate.

Interest Rate Fair Value Hedges -- The Company enters into interest rate
swaps to convert some of its fixed-rate long term debt to floating-rate long
term debt. Hedged items in fair value hedges are marked-to-market with the
respective derivative instruments. Accordingly, the Company's hedged fixed-rate
debt is carried at fair value. The terms of the outstanding swap and the
associated debt are matched at December 31, 2001 which permits the assumption of
no ineffectiveness, as defined by Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities." As such, for the life of the swap no ineffectiveness will be
recognized.

Goodwill -- Goodwill is the cost of an acquisition less the fair value of
the net assets of the acquired business. Prior to January 1, 2002, the Company
amortized goodwill on a straight-line basis over the useful lives of the
acquired assets, ranging from 15 to 20 years. The amount of goodwill reported on
the Consolidated Balance Sheets as of December 31, 2001 was $421.2 million, net
of accumulated amortization of $60.9 million. The amount of goodwill as of
December 31, 2000 was $376.2 million, net of accumulated amortization of $38.9
million The Company has implemented SFAS No. 142, "Goodwill and Other Intangible
Assets" as of

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

January 1, 2002. For information on the impact of SFAS No. 142 on goodwill and
goodwill amortization see the New Accounting Standards section of this footnote.
(See Notes 3 and 4 for information on significant goodwill additions.)

Property, Plant and Equipment -- Property, plant and equipment are stated
at original cost. Depreciation is computed using the straight-line method over
the estimated useful lives of the individual assets (see Note 8). The costs of
maintenance and repairs, which are not significant improvements, are expensed
when incurred. Interest totaling $0.8 million for 2001, $0.3 million for 2000
and $0.9 million for 1999 has been capitalized on construction projects.

Impairment of Long-Lived Assets -- The Company reviews the recoverability
of long-lived assets and intangible assets when circumstances indicate that the
carrying amount of the asset may not be recoverable. This evaluation is based on
undiscounted cash flow projections. For the years presented, there has been no
impairment.

Revenue Recognition -- The Company recognizes revenues on sales of natural
gas and petroleum products in the period of delivery and transportation revenues
in the period service is provided. For gathering services, the Company receives
fees from the producers to bring the natural gas from the wellhead to the
processing plant. For processing services, the Company either receives fees or
commodities as payment for these services, depending on the type of contract.
Under the Percentage-of-Proceeds contract type, the Company is paid for its
services by keeping a percentage of the NGLs produced and the residue gas
resulting from processing the natural gas. Under a Keep-Whole contract, the
Company keeps a portion of the NGLs produced, but returns the equivalent British
thermal unit ("Btu") content of the gas back to the producer. The Company also
receives fees for further fractionation of the NGLs produced, for transportation
and storage of NGLs and residue gas. In addition, the Company recognizes revenue
for its NGL and residue gas marketing activities.

Significant Customers -- Duke Energy Trading and Marketing, L.L.C.
("DETM"), an affiliated company, is a significant customer. Sales to DETM,
primarily residue gas, totaled $1,628.8 million during 2001, $1,444.0 million
during 2000 and $684.0 million during 1999.

Unamortized Debt Premium, Discount and Expense -- Premiums, discounts and
expenses incurred with the issuance of outstanding long term debt are amortized
over the terms of the debt issues.

Natural Gas Liquids Sales and Purchases Contracts -- Natural gas liquids
sales and purchases contracts are amortized on a straight-line basis over the
contract lives, ranging from two to 15 years.

Environmental Expenditures -- 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 generate current or future revenue, are expensed. Liabilities for
these expenditures are recorded on an undiscounted basis when environmental
assessments and/or clean-ups are probable and the costs can be reasonably
estimated. Recorded environmental liabilities were $40.0 million at the end of
2001 and $38.7 million at the end of 2000. (See Note 14).

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

Foreign Currency Translation -- The Company translates assets and
liabilities of its Canadian operations, where the Canadian dollar is the
functional currency, at the year-end exchange rates. Revenues and expenses are
translated using average exchange rates during the year. Foreign currency
translation adjustments are included in the Consolidated Statements of
Comprehensive Income.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Income Taxes -- The Company follows the asset and liability method of
accounting for income taxes. Deferred taxes are provided for temporary
differences in the tax and financial reporting basis of assets and liabilities
(see Note 10). At March 31, 2000, the Company converted to a limited liability
company which is a pass-through entity for income tax purposes. As a result,
substantially all of the existing net deferred tax liability of $327.0 million
was eliminated and a corresponding income tax benefit recorded. Going forward,
income taxes will consist primarily of miscellaneous state, local and franchise
taxes. In addition, the Company has Canadian subsidiaries that are levied
certain foreign taxes.

In connection with the Combination (see Note 3), the Company is required to
make quarterly distributions to Duke Energy and Phillips Petroleum Company
("Phillips") based on allocated taxable income. The limited liability company
agreement, as amended, provides for taxable income to be allocated in accordance
with the Internal Revenue Code section 704(c). This Code Section accounts for
the variation between the adjusted tax basis and the book value of assets
contributed to the joint venture. The distribution is based on the highest
taxable income allocated to either member, with the other member receiving a
proportionate amount to maintain the ownership capital accounts at 69.7% for
Duke Energy and 30.3% for Phillips. As of December 31, 2001 and 2000, the total
estimated distributions due to the members were approximately $45.7 and $127.6
million, respectively.

Stock Based Compensation -- Under Duke Energy's 1998 Long Term Incentive
Plan, stock options for Duke Energy's common stock may be granted to the
Company's key employees. The Company accounts for stock-based compensation using
the intrinsic method of accounting. Under this method, any compensation cost is
measured as the quoted market price of stock at the date of the grant less the
amount an employee must pay to acquire the stock. Restricted stock grants and
Company performance awards are recorded as compensation cost over the requisite
vesting period based on the market value on the date of the grant. (See Note 15
for pro forma disclosures using the fair value accounting method.) All
outstanding common stock amounts and compensation awards have been adjusted to
reflect Duke Energy's two-for-one common stock split effected January 26, 2001.
(See Note 15 for additional information on the stock split.)

Cumulative Effect of Change in Accounting Principle -- The Company adopted
SFAS No. 133 on January 1, 2001. In accordance with the transition provisions of
SFAS No. 133, the Company recorded a cumulative-effect adjustment of $0.4
million as a reduction in earnings and a cumulative-effect adjustment increasing
OCI and member's equity by $6.6 million. For the year ended December 31, 2001,
the Company reclassified as earnings $12.1 million of losses from OCI for
derivatives included in the transition adjustment related to hedge transactions
that settled. The amount reclassified out of OCI will be different from the
amount included in the transition adjustment due to market price changes since
January 1, 2001.

New Accounting Standards -- In June 2001, the Financial Accounting
Standards Board ("FASB") issued SFAS No. 141, "Business Combinations," and SFAS
No. 142, "Goodwill and Other Intangible Assets."

SFAS No. 142 is effective for fiscal years beginning after December 15,
2001 and will be adopted by the Company as of January 1, 2002. SFAS No. 142
requires that goodwill no longer be amortized over an estimated useful life, as
previously required. Instead, goodwill amounts will be subject to a
fair-value-based annual impairment assessment. The standard also requires
certain identifiable intangible assets to be recognized separately and amortized
as appropriate. No such intangibles have been identified at the Company. The
Company expects the adoption of SFAS No. 142 to have an impact on future
financial statements, due to the discontinuation of goodwill amortization
expense. For 2001, goodwill amortization expense was $22.0 mil-

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

lion. The Company has evaluated the fair value evidence and has concluded that
there is no impairment of goodwill as of January 1, 2002.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements for
retirement obligations associated with tangible long-lived assets. It is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. The Company is currently assessing the new standard and has not yet
determined the impact on its consolidated results of operations, cash flows or
financial position.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." The new rules supersede SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." The new rules retain many of the fundamental
recognition and measurement provisions of SFAS No. 121, but significantly change
the criteria for classifying an asset as held-for-sale. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001. The Company has
evaluated the new standard, and management believes that it will have no
material effect on its consolidated results of operations or financial position.

Reclassifications -- Some amounts reported in prior periods have been
reclassified in the Consolidated Financial Statements to conform to current
classifications.

3. COMBINATION

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

The Combination with Phillips has been accounted for as a purchase business
combination in accordance with Accounting Principles Board Opinion No. 16
"Accounting for Business Combinations." The Phillips assets, net of liabilities,
have been valued at $1,919.8 million, excluding $20.1 million of acquisition
costs. The following is a summary of the allocated purchase price (in millions):

<Table>

Property, plant and equipment............................... $1,634.7
Goodwill.................................................... 291.1
Current assets.............................................. 228.3
Other noncurrent assets..................................... 57.7
Current liabilities......................................... (228.3)
Other noncurrent liabilities................................ (43.6)
--------
Total purchase price.............................. $1,939.9
========
</Table>

Unaudited Pro Forma Disclosures -- Revenues for the years ended December
31, 2000 and 1999, on a pro forma basis would have increased $542.4 million and
$1,095.7 million, respectively, and net income for the years ended December 31,
2000 and 1999, on a pro forma basis would have increased by $65.7 million and
$21.2 million, respectively, if the acquisition of the Phillips midstream
business had occurred at the beginning of 1999.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

TEPPCO General Partner -- On March 31, 2000, and in connection with the
Combination, Duke Energy contributed the general partner of TEPPCO Partners,
L.P. ("TEPPCO") to Field Services LLC. In connection with the contribution of
the general partner of TEPPCO, the Company recorded an investment in TEPPCO of
$2.1 million and increased equity by $2.1 million.

TEPPCO is a publicly traded master limited partnership that owns and
operates a network of pipelines and storage and terminal facilities for refined
products, liquefied petroleum gases, liquefied natural gas, petrochemicals,
natural gas gathering and crude oil. The general partner is responsible for
TEPPCO's management and operations. Because Field Services LLC owns the general
partner of TEPPCO, it has the right to receive incentive cash distributions from
TEPPCO in addition to a 2% share of distributions based on the general partner
interest. At TEPPCO's 2001 per unit distribution level, the general partner
received approximately 21% of the cash distributed by TEPPCO to its partners.
Due to the general partner's share of unit distributions and degree of control
exercised through its management of the partnership and other partnership
governance issues, the Company's investment in TEPPCO is accounted for under the
equity method.

4. ACQUISITIONS AND DISPOSITIONS

Acquisition of Additional Equity Interests -- On July 10, 2001, the Company
acquired additional interests in Mobile Bay Processing Partners, Gulf Coast NGL
Pipeline, L.L.C. and Dauphin Island Gathering Partners from MCNIC Energy
Enterprise Inc. ("MCNIC") for approximately $66.2 million. This acquisition of
additional interests has been accounted for as a purchase business combination
in accordance with Accounting Principles Board Opinion No. 16. As a result of
these acquisitions, the Company has controlling interests in each of the
affiliates, and the assets and liabilities and results of operations of the
three affiliates have been consolidated in the Company's financial statements
since the date of the purchases with an offsetting amount recorded as minority
interest. The pro forma impact of the acquisition on the Company's results of
operations was not material.

Canadian Midstream Services, Ltd. -- On May 1, 2001, the Company acquired
the outstanding shares of Canadian Midstream Services, Ltd. ("CMSL") for a
purchase price of approximately $162.0 million. The purchase price included
assumed debt of approximately $49.3 million. The acquisition was accounted for
under the purchase method of accounting, and the assets and liabilities and
results of operations of CMSL have been consolidated in the Company's financial
statements since the date of purchase. On a pro forma basis, revenues and net
income for the year ended December 31, 2001 would have increased $7.8 million
and $1.4 million, respectively, if the acquisition of CMSL had occurred on
January 1, 2001. The following is a summary of the allocated purchase price (in
millions):

<Table>

Property, plant and equipment............................... $139.0
Goodwill.................................................... 53.7
Current assets.............................................. 14.0
Current liabilities......................................... (57.3)
Other noncurrent liabilities................................ (35.9)
------
Total purchase price.............................. $113.5
======
</Table>

Gas Supply Resources, Inc. -- On April 30, 2001, the Company acquired in a
purchase transaction, Gas Supply Resources, Inc. ("GSRI"), a propane wholesaler
located in the Northeast, for approximately $45.0 million. The pro forma impact
of the acquisition on the Company's results of operations was not material.
Goodwill of $28.1 million has been recorded as a result of allocating the
purchase price to the individual assets and liabilities acquired.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Disposition of NGL Pipeline Assets -- On December 31, 2000, the Company
sold pipeline assets to TEPPCO for $91.0 million. The NGL pipeline assets sold
included the Panola Pipeline and the San Jacinto Pipeline. TEPPCO also assumed
the lease of a 34 mile condensate pipeline. A $12.0 million gain and a $3.2
million deferred gain was recorded in connection with the sale.

Conoco and Mitchell Assets -- On March 31, 2000, Field Services LLC
acquired gathering and processing facilities located in central Oklahoma from
Conoco, Inc. and Mitchell Energy & Development Corp. Field Services LLC paid
cash of $99.8 million, and exchanged its interests in certain gathering and
marketing joint ventures located in southeast Texas having a total fair value of
$42.0 million as consideration for these facilities. The pro forma impact of the
acquisition on the Company's results of operations was not material.

Union Pacific Fuels, Inc. -- On March 31, 1999, the Company acquired the
assets and assumed certain liabilities of Union Pacific Fuels, Inc. ("UP
Fuels"), a wholly owned subsidiary of Union Pacific Resources Company ("UPR"),
for a total purchase price of $1,359.0 million. The acquisition was accounted
for under the purchase method of accounting, and the assets and liabilities and
results of operations of UP Fuels have been consolidated in the Company's
financial statements since the date of purchase. On a pro forma basis, revenues
and net income for the year ended December 31, 1999 would have increased $298.0
million and $3.4 million, respectively, if the acquisition of UP Fuels had
occurred on January 1, 1999. In connection with the acquisition, $77.6 million
of goodwill was recorded.

5. AGREEMENTS AND TRANSACTIONS WITH DUKE ENERGY

Services Agreement with Duke Energy -- In connection with the Combination,
the Company entered into a services agreement with Duke Energy and some of its
subsidiaries, dated March 14, 2000. Under this agreement, Duke Energy and those
subsidiaries will provide the Company with various staff and support services,
including information technology products and services, payroll, employee
benefits, insurance, cash management, ad valorem taxes, treasury, media
relations, printing, records management, legal functions and investor services.
These services are priced on the basis of a monthly charge which management
believes approximates market prices. Additionally, the Company may use other
Duke Energy services subject to hourly rates, including legal, insurance,
internal audit, tax planning, human resources and security departments. This
agreement, as amended, expires on December 31, 2002. Expenses resulting from
this agreement were $10.0 million and $7.4 million in 2001 and 2000,
respectively.

License Agreement -- In connection with the Combination, Duke Energy has
licensed to the Company a non-exclusive right to use the phrase "Duke Energy"
and its logo and certain other trademarks in identifying the Company's
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 the Company is
less than or equal to 35%; or Duke Energy no longer controls, directly or
indirectly, the management and policies of the Company.

Transactions between Duke Energy and the Company -- The Company sells a
portion of its residue gas and NGLs to, purchases raw natural gas and other
petroleum products from, and provides gathering and transportation services to
Duke Energy and its subsidiaries at contractual prices that have approximated
market prices in the ordinary course of the Company's business. The Company
anticipates continuing to purchase and sell these commodities and provide these
services to Duke Energy in the ordinary course of business. The Company's total
revenues from these activities were approximately $1,648.5 million, $1,459.2
million and $684.0 million for the years ended December 31, 2001, 2000 and 1999,
respectively.

6. AGREEMENTS AND TRANSACTIONS WITH PHILLIPS

Long Term NGLs Purchases Contract with Phillips -- In connection with the
Combination, the Company has agreed to maintain the NGL Output Purchase and Sale
Agreement (the "Phillips NGL

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

Transactions between Phillips and the Midstream Business Acquired from
Phillips -- Through March 31, 2000, the Phillips' businesses (the "Phillips
Combined Subsidiaries") that owned the midstream natural gas assets that were
contributed to the Company in the Combination had conducted a series of
transactions with Phillips in which the Phillips Combined Subsidiaries sold a
portion of their residue gas and other by-products to Phillips at contractual
prices that approximated market prices. In addition, the Phillips Combined
Subsidiaries purchased raw natural gas from Phillips at contractual prices that
have approximated market prices. The Company is continuing these transactions in
the ordinary course of business. The Company's total revenues from these
activities were approximately $816.2 million and $942.3 million for the years
ended December 31, 2001 and 2000, respectively.

7. INVENTORIES

A summary of inventories by category follows:

<Table>
<Caption>
DECEMBER 31,
-----------------
2001 2000
------- -------
(IN THOUSANDS)

Gas held for resale......................................... $32,553 $11,720
NGLs........................................................ 44,310 67,441
Materials and supplies...................................... 6,072 7,359
------- -------
Total inventories................................. $82,935 $86,520
======= =======
</Table>

8. PROPERTY, PLANT AND EQUIPMENT

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

<Table>
<Caption>
DECEMBER 31,
DEPRECIATION ------------------------
RATES 2001 2000
------------ ----------- ----------
(IN THOUSANDS)

Gathering....................................... 4% - 6% $ 2,308,905 $2,409,136
Processing...................................... 4% 1,786,431 1,802,824
Transmission.................................... 4% 1,241,408 424,120
Underground storage............................. 2% - 5% 91,205 77,174
General plant................................... 20% - 33% 126,125 83,175
Construction work in progress................... 253,831 154,330
----------- ----------
5,807,905 4,950,759
Accumulated depreciation...................... (1,095,945) (798,279)
----------- ----------
Property, plant and equipment, net............ $ 4,711,960 $4,152,480
=========== ==========
</Table>

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. INVESTMENTS IN AFFILIATES

The Company has investments in the following businesses accounted for using
the equity method:

<Table>
<Caption>
DECEMBER 31,
2001 -------------------
OWNERSHIP 2001 2000
--------- -------- --------
(IN THOUSANDS)

TEPPCO Partners, L.P................................. 2.00% $ 13,401 $ 3,323
Mont Belvieu I....................................... 20.00% 37,706 38,936
Sycamore Gas System General Partnership.............. 48.45% 18,803 22,172
Main Pass Oil Gathering.............................. 33.33% 16,817 17,131
Tri-States NGL Pipeline, LLC......................... 10.00% 13,971 --
Black Lake Pipeline.................................. 50.00% 8,996 8,751
Fox Plant LLC........................................ 50.00% 8,247 8,045
Dauphin Island Gathering Partners(1)................. 71.84% -- 102,440
Mobile Bay Processing Partners(1).................... 57.61% -- 34,571
Other affiliates..................................... Various 14,311 26,182
-------- --------
Total investments in affiliates............ $132,252 $261,551
======== ========
</Table>

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

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.

Tri-States NGL Pipeline, LLC -- Tri-States NGL Pipeline, LLC owns 169 miles
of pipeline, extending from a point near Mobile Bay, Alabama to a point near
Kenner, Louisiana.

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.

Fox Plant LLC -- Fox Plant LLC is a limited liability company formed for
the purpose of constructing, owning and operating a gathering facility and gas
processing plant in Carter County, Oklahoma.

- ----------

(1) On July 10, 2001, the Company acquired additional interests in Mobile Bay
Processing Partners and Dauphin Island Gathering Partners. As a result of
these acquisitions, the assets and liabilities and results of operations of
the three affiliates have been consolidated in the Company's Consolidated
Financial Statements since the date of the purchase (see Note 4).

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<Table>
<Caption>
2001 2000 1999
------- ------- -------
(IN THOUSANDS)

TEPPCO Partners, L.P.................................... $24,517 $10,589 $ --
Mont Belvieu I.......................................... (766) (501) 440
Sycamore Gas System General Partnership................. (302) 44 142
Main Pass Oil Gathering................................. 3,768 2,973 3,638
Tri-States NGL Pipeline, LLC............................ 554 -- --
Black Lake Pipeline..................................... 1,322 1,833 1,141
Fox Plant LLC........................................... 202 508 --
Dauphin Island Gathering Partners....................... 1,287 3,835 5,974
Mobile Bay Processing Partners.......................... (971) 2,413 2,307
Ferguson-Burleson....................................... -- 651 5,600
Westana Gathering Company............................... -- 346 1,339
Other affiliates........................................ 458 4,733 1,921
------- ------- -------
Total equity earnings......................... $30,069 $27,424 $22,502
======= ======= =======
</Table>

Distributions in excess of earnings were $11.3 million, $4.2 million and
$9.5 million in 2001, 2000 and 1999, respectively.

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

<Table>
<Caption>
2001 2000 1999
--------- --------- --------
(IN THOUSANDS)

Income statement:
Operating revenues............................... $ 211,792 $ 242,900 $452,118
Operating expenses............................... (167,289) 216,334 374,079
Net income....................................... 40,352 27,278 55,606
Balance sheet:
Current assets................................... $ 73,466 $ 97,478
Noncurrent assets................................ 599,727 749,772
Current liabilities.............................. (35,014) (79,567)
Noncurrent liabilities........................... (260,583) (133,058)
--------- ---------
Net assets............................... $ 377,596 $ 634,625
========= =========
</Table>

10. INCOME TAXES

At March 31, 2000, the Company converted to a limited liability company
which is a pass-through entity for income tax purposes. As a result,
substantially all of the existing net deferred tax liability of $327.0 million
was eliminated and a corresponding income tax benefit was recorded.

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

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Income tax as presented in the Statements of Income is summarized as
follows:

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
------ --------- --------
(IN THOUSANDS)

Current:
Federal............................................. $ -- $ (5,066) $(46,429)
State............................................... 480 2,130 (8,843)
Foreign............................................. 1,324 -- --
------ --------- --------
Total current............................... 1,804 (2,936) (55,272)
------ --------- --------
Deferred:
Federal............................................. -- (268,911) 73,201
State............................................... 979 (39,090) 13,100
------ --------- --------
Total deferred.............................. 979 (308,001) 86,301
------ --------- --------
Total income tax expense.............................. $2,783 $(310,937) $ 31,029
====== ========= ========
</Table>

Total income tax expense for the year ended December 31, 1999 differed from
the amount computed by applying the federal income tax rate to earnings before
income tax. The reasons for this difference are as follows (in thousands):

<Table>

Federal income tax rate..................................... 35.0%
=======
Income tax, computed at the statutory rate.................. $26,025
Adjustments resulting from:
State income tax, net of federal income tax effect........ 2,863
Non-deductible amortization and other..................... 2,141
-------
Total income tax.................................. $31,029
=======
</Table>

11. FINANCING

Credit Facility with Financial Institutions -- In March 2000, Field
Services LLC entered into a $2,800.0 million credit facility with several
financial institutions. On April 3, 2000, Field Services LLC borrowed $2,790.9
million in the commercial paper market to fund one-time cash distributions of
$1,524.5 million to Duke Energy and $1,219.8 million to Phillips, and to meet
working capital requirements. The credit facility matured on March 30, 2001, and
was replaced by a new $675.0 million revolving credit facility (the "Facility"),
of which $150.0 million can be used for letters of credit. The Facility is used
to support the Company's commercial paper program and for working capital and
other general corporate purposes. The Facility matures on March 29, 2002,
however, any outstanding loans under the Facility at maturity may, at the
Company's option, be converted to a one-year term loan. The Facility requires
the Company to maintain at all times a debt to total capitalization ratio of
less than or equal to 53%. The Facility bears interest at a rate equal to, at
the Company's option, either (1) LIBOR plus 0.75% per year or (2) the higher of
(a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per
year. At December 31, 2001, there were no borrowings against the Facility. At
December 31, 2001 the Company had a $45.0 million outstanding Irrevocable
Standby Letter of Credit expiring March 29, 2002. In addition, the Company had
$213.0 million and $346.4 million in outstanding commercial paper at December
31, 2001 and 2000, respectively with maturities ranging from two days to 19 days
and annual interest rates ranging from 7.05% to 7.6%. The weighted average
interest rate on the outstanding commercial paper was 2.53% and 7.39%

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

for the years ended December 31, 2001 and 2000, respectively. The amount of the
Company's outstanding commercial paper never exceeded the available amount under
the Facility.

Preferred Financing -- In August 2000, the Company issued $300.0 million of
preferred member interests to affiliates of Duke Energy and Phillips. The
proceeds from this financing were used to repay a portion of the Company's
outstanding commercial paper. The preferred member interests are entitled to
cumulative preferential distributions of 9.5% per annum payable, unless
deferred, semi-annually. The Company has the right to defer payments of
preferential distributions on the preferred member interests, other than certain
tax distributions, at any time, for up to 10 consecutive semiannual periods.
Deferred preferred distributions will accrue additional amounts based on the
preferential distribution rate (plus 0.5% per annum) to the date of payment. The
preferred member interests, together with all accrued and unpaid preferential
distributions, must be redeemed and paid on the earlier of the thirtieth
anniversary date of issuance or consummation of an initial public offering of
equity securities. For the years ended December 31, 2001 and 2000, the Company
has paid preferential distributions of $28.5 million and $11.7 million,
respectively.

Debt Securities -- Long term debt at December 31, 2001 and 2000 was as
follows:

<Table>
<Caption>
PRINCIPAL/DISCOUNT
----------------------- INTEREST
2001 2000 ISSUE DATE RATE DUE DATE
---------- ---------- ----------------- -------- -----------------
(IN THOUSANDS)

Debt Securities........... $ 600,000 $ 600,000 August 16, 2000 7 1/2% August 16, 2005
800,000 800,000 August 16, 2000 7 7/8% August 16, 2010
300,000 300,000 August 16, 2000 8 1/8% August 16, 2030
250,000 -- February 2, 2001 6 7/8% February 1, 2011
300,000 -- November 9, 2001 5 3/4% November 15, 2006
Interest rate swap........ (4,659) --
Capitalized leases........ 3,288 --
Unamortized discount...... (13,595) (11,843)
---------- ----------
Net long term debt........ $2,235,034 $1,688,157
========== ==========
</Table>

The notes mature and become payable on the respective due dates, and are
not subject to any sinking fund provisions. Debt securities maturing over the
next five years include $600.0 million in 2005 and $300.0 million in 2006.
Interest is payable semiannually. The notes are redeemable at the option of the
Company. The Company used the proceeds from the issuance of the debt securities
to repay short term debt.

The Company is guarantor of approximately $28.9 million of debt associated
with an unconsolidated subsidiary. Assets of the unconsolidated subsidiary are
pledged as collateral for the debt.

12. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND CREDIT RISK

Commodity price risk -- The Company's principal operations of gathering,
processing, and storage of natural gas, and the accompanying operations of
processing, fractionation, transportation, and marketing of natural gas liquids
create commodity price risk exposure due to market fluctuations in commodity
prices, primarily with respect to the prices of natural gas liquids. As an owner
and operator of natural gas processing

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and other midstream assets, the Company has an inherent exposure to market
variables and commodity price risk. The amount and type of price risk is
dependent on the underlying natural gas acquisition contracts entered in to
purchase and process natural gas feedstock. Risk is also dependent on the types
and mechanisms for sales of natural gas and natural gas liquid products
produced, processed, transported, or stored.

Energy trading (market) risk -- Certain of the Company's subsidiaries are
engaged in the business of trading energy related products and services
including managing purchase and sales portfolios, storage contracts and
facilities, and transportation commitments for products. These energy trading
operations are exposed to market variables and commodity price risk with respect
to these products and services, and may enter into physical contracts and
financial instruments with the objective of realizing a positive margin from the
purchase and sales of commodity-based instruments.

Corporate economic risks -- The Company enters into debt arrangements that
are exposed to market risks related to changes in interest rates. The Company
periodically utilizes interest rate lock agreements and interest rate swaps to
hedge interest rate risk associated with new debt issuances. The Company's
primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to
total debt for the Company's debt rating; (2) reducing volatility of earnings
resulting from interest rate fluctuations; and (3) locking in attractive
interest rates based on historical rates.

Counterparty risks -- The Company has credit risk from its extension of
credit for sales of energy products and services, and credit risk with its
counterparties in terms of settlement risk and performance risk. On all
transactions where the Company is exposed to credit risk, the Company analyzes
the counterparties' financial condition prior to entering into an agreement,
establishes credit limits and monitors the appropriateness of these limits on an
ongoing basis.

Commodity cash flow hedges -- The Company uses cash flow hedges, as
specifically defined by SFAS No. 133, to reduce the potential negative impact
that commodity price changes could have on the Company's earnings, and its
ability to adequately plan for cash needed for debt service, dividends and
capital expenditures. The Company's primary corporate hedging goals include (1)
maintaining minimum cash flows to fund debt service, dividends, production
replacement and maintenance capital projects; (2) avoiding disruption of the
Company's growth capital and value creation process; and (3) retaining a high
percentage of potential upside relating to price increases of natural gas
liquids.

The Company utilizes natural gas, crude oil and NGL swaps and options to
hedge the impact of market fluctuations in the price of natural gas liquids and
other energy-related products. For the year ended December 31, 2001, the Company
recognized a net gain of $4.7 million, of which a $1.4 million gain represented
the total ineffectiveness of all cash flow hedges and a $3.3 million gain
represented the total derivative settlements. The time value of the options, a
recognized $1.4 million gain for the year ended December 31, 2001, was excluded
in the assessment of hedge effectiveness. The time value of the options is
included in Sales of Natural Gas and Petroleum Products in the Consolidated
Statements of Income. No derivative gains or losses were reclassified from OCI
to current period earnings as a result of the discontinuance of cash flow hedges
related to certain forecasted transactions that are probable of not occurring.

Gains and losses on derivative contracts that are reclassified from
accumulated OCI to current period earnings are included in the line item in
which the hedged item is recorded. As of December 31, 2001, $51.5 million of the
deferred net gains on derivative instruments accumulated in OCI are expected to
be reclassified as earnings during the next 12 months as the hedge transactions
occur; however, due to the volatility of the commodities markets, the
corresponding value in OCI is subject to change prior to its reclassification
into earnings. The maximum term over which the Company is hedging its exposure
to the variability of future cash flows is 24 months.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Commodity fair value hedges -- The Company utilizes fair value hedges to
hedge exposure to changes in the fair value of an asset or a liability (or an
identified portion thereof) that is attributable to price risk. The Company
hedges producer price locks (fixed price gas purchases) and market locks (fixed
price gas sales) to reduce the Company's exposure to fixed price risk via
swapping out the fixed price risk for a floating price position (NYMEX or index
based).

For the year ended December 31, 2001, the gains or losses representing the
ineffective portion of the Company's fair value hedges were not material. All
components of each derivative's gain or loss are included in the assessment of
hedge effectiveness, unless otherwise noted. The Company did not have any firm
commitments that no longer qualified as fair value hedge items and therefore,
did not recognize an associated gain or loss.

Commodity Derivatives -- Non-Trading -- Historically, the Company's
commodity price risk management program had been directed by Duke Energy under
its centralized program for controlling, managing and coordinating its
management of risks. During the three months ended March 31, 2000 and the year
ended December 31, 1999, the Company recorded hedging losses of $46.7 million
and $34.0 million, respectively, under Duke Energy's centralized program. As of
March 31, 2000, the commodity positions then held by the Company under the
centralized program were transferred to Duke Energy.

Effective April 1, 2000, the Company began directing its risk management
activities, including commodity price risk for market fluctuations in the price
of NGLs, independently of Duke Energy. During the nine months ended December 31,
2000, the Company recorded a hedging loss of $81.0 million under the Company's
self-directed risk management program.

In 1999, the Company managed its exposure to risk from existing assets,
liabilities and commitments by hedging the impact of market fluctuations. At
December 31, 2000, the Company held or issued several commodity derivatives that
reduce exposure to market fluctuations in the price and transportation costs of
natural gas and NGLs. At December 31, 2000, these commodity derivatives extended
for periods of up to 10 years. The gains, losses and costs related to
non-trading commodity derivatives are not recognized until the underlying
physical transaction closes. At December 31, 2000, the Company had unrealized
net losses of $15.3 million related to non-trading commodity derivatives.

Commodity Derivatives -- Trading -- The trading of energy related products
and services exposes the Company to the fluctuations in the market values of
traded instruments. The Company manages its traded instrument portfolio with
strict policies which limit exposure to market risk and require daily reporting
to management of potential financial exposure. These policies include
statistical risk tolerance limits using historical price movements to calculate
a daily earnings at risk measurement.

Fair Values of Commodity Derivatives -- Trading:

<Table>
<Caption>
2001 2000
---------------------- ---------------------
ASSETS LIABILITIES ASSETS LIABILITIES
-------- ----------- ------- -----------
(IN THOUSANDS)

Fair value at December 31.................... $135,456 $97,990 $46,185 $51,179
</Table>

Interest rate fair value hedge -- In October 2001, the Company entered an
interest rate swap to convert the fixed interest rate of $250.0 million of debt
securities that were issued in August 2000 to floating rate debt. The interest
rate fair value hedge is at a floating rate based on six-month LIBOR rates,
which is re-priced semiannually through 2005. The swap meets conditions which
permit the assumption of no ineffectiveness, as defined by SFAS 133. As such,
for the life of the swap no ineffectiveness will be recognized. As of December
31, 2001, the fair value of the interest rate swap of ($4.6) million was
included in the Consolidated Balance Sheets as Unrealized Gains or Losses on
Trading and Hedging Transactions with an offset to the underlying debt included
in Long Term Debt.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The following fair value amounts have been determined by the Company using
available market information and appropriate valuation methodologies. However,
considerable judgment is 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 Company could realize in a
current market exchange. The use of different market assumptions and/or
estimation methods may have a material effect on the estimated fair value
amounts.

<Table>
<Caption>
DECEMBER 31, 2001 DECEMBER 31, 2000
---------------------------- ----------------------------
CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR
AMOUNT VALUE AMOUNT VALUE
----------- -------------- ----------- --------------
(IN THOUSANDS)

Accounts receivable............. $ 887,449 $ 887,449 $ 1,400,676 $ 1,400,676
Notes receivable................ -- -- 29,465 29,465
Accounts payable................ (722,628) (722,628) (1,375,815) (1,375,815)
Natural gas, NGL and oil hedge
and trading contracts......... 89,905 89,905 (4,994) (20,292)
Short term debt................. (212,955) (212,955) (346,410) (346,410)
Long term debt.................. (2,235,034) (2,342,795) (1,688,157) (1,795,371)
</Table>

The fair value of cash and cash equivalents, accounts receivable, accounts
payable, and short term debt 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.

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. The estimated fair value of options is determined by the
Black-Scholes options valuation model.

The estimated fair value of long term debt is determined by prices obtained
from market quotes.

14. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation -- The midstream natural gas industry has seen a 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. A
number of these cases are now being brought as class actions. The Company and
its subsidiaries are currently named as defendants in some of these cases.
Management believes the Company and its subsidiaries have meritorious defenses
to these cases, and therefore will continue to defend them vigorously. However,
these class actions can be costly and time consuming to defend.

Management believes that the final disposition of these proceedings will
not have a material adverse effect on the consolidated results of operations or
financial position of the Company.

In December 1998, Williams Field Services ("Williams") sued Union Pacific
Resources Company ("UPRC") and certain affiliates of the Company in Carbon
County, Wyoming District Court to enforce its rights under a preferential
purchase right. Williams is the majority owner and operator of the Echo Springs
Gas Plant and Wamsutter Gathering System in which the Company acquired an
interest from UPRC (the "Acquired Assets"). Williams' suit claims that they
believe a change of control of the corporate entity that held the UPRC interest
in the Acquired Assets occurred at the time of the merger between the Company
and

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UPRC and triggered Williams' preferential purchase right. On November 22, 1999,
the District Court granted UPRC and the Company's motion for summary judgment.
Williams appealed this decision on March 23, 2000 to the Wyoming Supreme Court
and on June 20, 2001, the Wyoming Supreme Court reversed the District Court's
summary judgment ruling and ordered that a summary judgement be entered for
Williams. A request for rehearing was denied. On February 28, 2002, the Company
and Williams resolved all issues associated with this matter by closing an
exchange transaction in which the Company exchanged the Acquired Assets for
certain assets of Williams in the Texas Panhandle and Western Oklahoma. This
transaction has been accounted for as a nonmonetary exchange in accordance with
Accounting Principles Board Opinion No. 29 "Accounting for Nonmonetary
Transactions." There is no gain or loss on the exchange as the fair value of the
assets received exceeds the book value of the Company's Acquired Assets.

Environmental -- On June 13, 2001, the Company received two administrative
Compliance Orders from the New Mexico Environment Department ("NMED") seeking
civil penalties for primarily historic air permit matters. One order alleges
specific permit non-compliance at 11 facilities that occurred periodically
between 1996 and 1999. Allegations under this order relate primarily to
emissions from certain compressor engines in excess of what were then new
operating permit limits. The other order alleges numerous unexcused excursions
from an hourly permit limit arising from upset events at the Company's Dagger
Draw facility's sulfur recovery unit between 1997 and 2001. NMED applied its
civil penalty policy to the alleged violations and calculated the penalties to
be $10.4 million in the aggregate. NMED has initiated settlement discussions and
offered to resolve these matters for an amount lower than the calculated
penalties. The Company is continuing its discussions with NMED and anticipates
that it will resolve all issues relating to the alleged violations.

Management believes that the final disposition of these proceedings will
not have a material adverse effect on the consolidated results of operations or
financial position of the Company.
59

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other Commitments and Contingencies -- The Company utilizes assets under
operating leases in several areas of operation. Combined rental expense amounted
to $23.5 million, $20.2 million and $11.8 million in 2001, 2000 and 1999,
respectively. Minimum rental payments under the Company's various operating
leases for the years 2002 through 2006 are $8.3 million, $7.0 million, $5.4
million, $5.3 million and $3.5 million, respectively. Thereafter, payments
aggregate $6.4 million through 2011.

15. STOCK-BASED COMPENSATION

Under Duke Energy's 1998 Long Term Incentive Plan, stock options for Duke
Energy's common stock may be granted to the Company's key employees. Under the
plan, the exercise price of each option granted cannot be less than 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 term of 10 years.

On December 20, 2000, Duke Energy announced a two-for-one common stock
split effective January 26, 2001, to shareholders of record on January 3, 2001.
The following option information has been restated to reflect the stock split,
and appropriate adjustments have been made in the exercise price and number of
shares subject to stock options.

The following tables show information regarding options to purchase Duke
Energy's common stock granted to employees of the Company.

STOCK OPTION ACTIVITY

<Table>
<Caption>
WEIGHTED
AVERAGE
EXERCISE
OPTIONS PRICE
------- --------
(IN THOUSANDS)

Outstanding at December 31, 1998............................ 868 $22
Granted................................................... 1,756 27
Exercised................................................. (66) 13
Forfeited................................................. (36) 28
----- ---
Outstanding at December 31, 1999............................ 2,522 26
Granted................................................... 837 41
Exercised................................................. (568) 22
Forfeited................................................. (223) 27
----- ---
Outstanding at December 31, 2000............................ 2,568 31
Granted................................................... 815 38
Exercised................................................. (251) 27
Forfeited................................................. (144) 32
----- ---
Outstanding at December 31, 2001............................ 2,988 $33
===== ===
</Table>

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK OPTIONS AT DECEMBER 31, 2001

<Table>
<Caption>
OUTSTANDING
----------------------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
REMAINING EXERCISE EXERCISABLE EXERCISE
RANGE OF EXERCISE PRICES NUMBER LIFE (YEARS) PRICE NUMBER PRICE
- ------------------------ -------------- ------------ -------- -------------- --------
(IN THOUSANDS) (IN THOUSANDS)

$ 8 to $10................. 12 3.1 $10 12 $10
$11 to $16................. 24 3.3 12 24 12
$17 to $22................. 16 5.1 22 16 22
$23 to $28................. 1,258 7.4 26 533 26
$29 to $34................. 180 7.7 30 59 30
$35 to $40................. 814 10.0 38 -- --
> $40..................... 684 9.0 43 169 43
----- ---
Total................. 2,988 8.4 33 813 29
===== ===
</Table>

On December 21, 2000, there were approximately 403,000 exercisable options
with a $25 weighted average exercise price. On December 31, 1999, there were
382,000 options exercisable with a weighted average exercise price of $17 per
option.

No compensation cost related to the stock options has been recorded as the
intrinsic method of accounting is used and the exercise price of each option
granted equaled the market price on the date of grant. The weighted average fair
value of options granted was $10, $10 and $5 per option during 2001, 2000 and
1999, respectively. The fair value of each option granted was estimated on the
date of grant using the Black-Scholes options valuation model.

WEIGHTED-AVERAGE ASSUMPTIONS FOR OPTION-PRICING

<Table>
<Caption>
2001 2000 1999
------- ------- -------

Stock dividend yield...................................... 3.4% 3.7% 4.1%
Expected stock price volatility........................... 29.7% 25.1% 18.8%
Risk-free interest rates.................................. 5.0% 5.3% 5.9%
Expected option lives..................................... 7 years 7 years 7 years
</Table>

Stock-based compensation expense calculated using the Black-Scholes options
valuation model for 2001, 2000 and 1999 would have been $3.7 million, $2.9
million and $2.5 million, respectively and net income would have been $361.7
million, $678.2 million and $41.8 million, respectively.

Duke Energy granted performance awards of Duke Energy common stock to key
employees of the Predecessor Company under the 1998 Long Term Incentive Plan.
Performance awards under the 1998 plan vest over periods ranging from one to
seven years. Duke Energy did not award any performance awards in 2001 or 2000.
Duke Energy awarded 86,400 shares (fair value of approximately $2.3 million at
grant dates) in 1999. Compensation expense for the performance grants is charged
to the Company's earnings over the vesting period, and amounted to approximately
$217,000, $1.2 million, and $305,000, in 2001, 2000, and 1999, respectively.

Duke Energy granted phantom shares of Duke Energy common stock to employees
of the Predecessor Company under the 1998 Plan. Phantom stock awards under the
1998 Plan vest over periods ranging from one to four years. Duke awarded 34,190
shares (fair value of approximately $1.3 million at grant dates) in 2001 and
13,100 shares (fair value of approximately $0.6 million at grant date) in 2000.
Compensation expense for

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the stock grants is charged to the Company's earnings over the vesting period,
and amounted to approximately $300,000 in 2001. Compensation expense in 2000 was
immaterial.

In addition, Duke Energy granted restricted shares of Duke Energy common
stock to key employees of the Predecessor Company under the 1996 Stock Incentive
Plan. Restricted stock grants under the 1996 plan vest over periods ranging from
one to five years. No restricted shares were awarded in 2001. Duke Energy
awarded 28,526 restricted shares (fair value of approximately $822,000 at grant
dates) in 2000 and 11,100 shares (fair value of approximately $618,000 at grant
dates) in 1999. Compensation expense for the stock grants is charged to the
Company's earnings over the vesting period, and amounted to approximately
$418,000, $402,000, and $275,000, in 2001, 2000, and 1999, respectively.

16. PENSION AND OTHER BENEFITS

Effective March 31, 2000, participation by the Company's employees in Duke
Energy's non-contributory defined benefit retirement plan and employee savings
plan were terminated. Effective April 1, 2000, the Company's employees began
participation in the Company's employee savings plan, in which the Company
contributes 4% of each eligible employee's qualified wages. Additionally, the
Company matches employees' contributions to the plan up to 6% of qualified
wages. During 2001 and 2000, the Company expensed plan contributions of $14.1
million and $8.9 million, respectively.

Duke Energy has, and the Predecessor Company participated in, a
non-contributory trustee pension plan which covered eligible employees with
minimum service requirements using a cash balance formula. For eligible
employees of the Predecessor Company, the plan provides pension benefits 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 Company are as follows:

Components of Net Periodic Pension Costs

<Table>
<Caption>
YEARS ENDED
DECEMBER 31,
---------------
2000 1999
----- -------
(IN THOUSANDS)

Service cost benefit earned during year..................... $ 480 $ 1,280
Interest cost on projected benefit obligation............... 460 1,375
Expected return on plan assets.............................. (674) (2,307)
Amortization of net transition asset........................ (21) (85)
Amortization of prior service cost.......................... 8 34
Recognized actuarial loss................................... -- 6
----- -------
Net periodic pension cost................................... 253 303
Impact of terminating plan participation.................... 483 --
----- -------
Total pension cost.......................................... $ 736 $ 303
===== =======
</Table>

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Reconciliation of Funded Status to Pre-Funded Pension Costs

<Table>
<Caption>
DECEMBER 31,
2000
--------------
(IN THOUSANDS)

CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year..................... $ 21,846
Service cost................................................ 480
Interest cost............................................... 460
Intercompany transfers(a)................................... 128
Benefits paid............................................... (180)
Impact of terminating plan participation.................... (22,734)
--------
Benefit obligation at end of year........................... $ --
========
</Table>

<Table>
<Caption>
DECEMBER 31,
2000
--------------
(IN THOUSANDS)

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year.............. $ 33,827
Intercompany transfers(a)................................... 128
Actual return on plan assets................................ 37
Employer contributions...................................... 736
Benefits paid............................................... (180)
Impact of terminating plan participants..................... (34,548)
--------
Fair value of plan assets at end of year.................... $ --
========
Pre-funded pension costs.................................... $ --
========
</Table>

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

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

Assumptions Used for Pension Benefit Accounting

<Table>
<Caption>
YEARS ENDED
DECEMBER 31,
-------------
2000 1999
----- -----

Discount rate............................................... 7.50% 7.50%
Rate of increase in compensation levels..................... 4.53% 4.50%
Expected long term rate of return on plan assets............ 9.25% 9.25%
</Table>

The Predecessor Company sponsored an employee savings plan which covered
substantially all employees. During 1999, the Company expensed plan
contributions of $3.6 million. The employee savings plan was terminated on March
31, 2000 in connection with the Combination.

The Predecessor Company's post-retirement benefits, in conjunction with
Duke Energy, consist of certain health care and life insurance benefits for
certain retired employees. Post-retirement benefits costs were not material in
2000 and 1999. The Company does not have any significant, continuing obligations
with respect to post-retirement benefits.

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

17. BUSINESS SEGMENTS

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

The following table sets forth the Company's segment information.

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
----------- ----------- ----------
(IN THOUSANDS)

Operating revenues:
Natural gas................................ $ 6,503,921 $ 7,036,003 $2,483,197
NGLs....................................... 5,030,897 3,652,120 1,365,577
Intersegment(a)............................ (1,937,153) (1,594,757) (390,464)
----------- ----------- ----------
Total operating revenues........... $ 9,597,665 $ 9,093,366 $3,458,310
----------- ----------- ----------
Margin:
Natural gas................................ $ 1,228,424 $ 1,169,286 $ 459,843
NGLs....................................... 55,376 48,662 33,170
----------- ----------- ----------
Total margin....................... $ 1,283,800 $ 1,217,948 $ 493,013
=========== =========== ==========
Other operating costs:
Natural gas................................ $ 364,664 $ 329,054 $ 182,062
NGLs....................................... 7,536 (8,142)(c) 1,707
Corporate.................................. 129,968 171,154 73,685
----------- ----------- ----------
Total other operating costs........ $ 502,168 $ 492,066 $ 257,454
=========== =========== ==========
Equity in earnings of unconsolidated
affiliates:
Natural gas................................ $ 28,899 $ 25,554 $ 20,917
NGLs....................................... 1,170 1,870 1,585
----------- ----------- ----------
Total equity in earnings of
unconsolidated affiliates........ $ 30,069 $ 27,424 $ 22,502
=========== =========== ==========
</Table>

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
----------- ----------- ----------
(IN THOUSANDS)

EBITDA(b):
Natural gas................................ $ 892,659 $ 865,786 $ 298,698
NGLs....................................... 49,010 58,674 33,048
Corporate.................................. (129,968) (171,154) (73,685)
----------- ----------- ----------
Total EBITDA....................... $ 811,701 $ 753,306 $ 258,061
=========== =========== ==========
Depreciation and amortization:
Natural gas................................ $ 264,445 $ 218,593 $ 119,425
NGLs....................................... 10,077 12,636 9,073
Corporate.................................. 4,408 3,633 2,290
----------- ----------- ----------
Total depreciation and
amortization..................... $ 278,930 $ 234,862 $ 130,788
=========== =========== ==========
EBIT(b):
Natural gas................................ $ 628,214 $ 647,193 $ 179,273
NGLs....................................... 38,933 46,038 23,975
Corporate.................................. (134,376) (174,787) (75,975)
----------- ----------- ----------
Total EBIT......................... $ 532,771 $ 518,444 $ 127,273
=========== =========== ==========
Corporate interest expense................... $ 165,670 $ 149,220 $ 52,915
=========== =========== ==========
Income before income taxes:
Natural gas................................ $ 628,214 $ 647,193 $ 179,273
NGLs....................................... 38,933 46,038 23,975
Corporate.................................. (300,046) (324,007) (128,890)
----------- ----------- ----------
Total income before income taxes... $ 367,101 $ 369,224 $ 74,358
=========== =========== ==========
Capital Expenditures:
Natural gas................................ $ 560,775 $ 356,542 $1,387,805
NGLs....................................... 10,911 1,284 177,070
Corporate.................................. 20,944 13,122 5,208
----------- ----------- ----------
Total Capital Expenditures......... $ 592,630 $ 370,948 $1,570,083
=========== =========== ==========
</Table>

<Table>
<Caption>
AS OF DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(IN THOUSANDS)

Total assets:
Natural gas............................................... $5,326,889 $4,896,542
NGLs...................................................... 258,177 219,282
Corporate(d).............................................. 1,045,143 1,412,173
---------- ----------
Total assets...................................... $6,630,209 $6,527,997
========== ==========
</Table>

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

(b) EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense.
EBIT is EBITDA less depreciation and amortization. These measures are not a
measurement presented in accordance with generally accepted accounting
principles and should not be considered 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 the Company's
profitability or liquidity. The measures are included as a supplemental
disclosure because it may provide useful information regarding the
Company's ability to service debt and to fund capital expenditures.
However, not all EBITDA or EBIT may be available to service debt. This
measure may not be comparable to similarly titled measures reported by
other companies.

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

18. QUARTERLY FINANCIAL DATA (UNAUDITED)

<Table>
<Caption>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)

2001
Operating revenue...... $3,380,072 $2,536,325 $1,681,127 $2,000,141 $9,597,665
Operating income....... 179,688 145,393 114,672 62,949 502,702
Net income............. 142,378 115,642 78,836 27,051 363,907
2000
Operating revenue...... $1,451,211 $2,172,360 $2,551,995 $2,917,800 $9,093,366
Operating income....... 55,627 136,881 152,501 146,011 491,020
Net income............. 361,900 92,229 114,304 111,728 680,161
</Table>

SCHEDULE II
DUKE ENERGY FIELD SERVICES, LLC

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
ADDITIONS
------------------------ PRINCIPAL CASH
BALANCE AT CHARGED TO PAYMENTS AND BALANCE AT
BEGINNING CHARGED TO OTHER RESERVE END OF
OF PERIOD EXPENSES ACCOUNTS(B) REVERSALS PERIOD
---------- ---------- ----------- -------------- ----------

DECEMBER 31, 2001:
Allowance for doubtful accounts..... $ 3.6 $3.3 $ -- $ (1.0) $ 5.9
Environmental....................... 38.7 -- 8.9 (7.6) 40.0
Litigation.......................... 28.7 -- 1.2 (22.4) 7.5
Other(a)............................ 18.6 -- 16.2 (22.7) 12.1
----- ---- ----- ------ -----
$89.6 $3.3 $26.3 $(53.7) $65.5
DECEMBER 31, 2000:
Allowance for doubtful accounts..... $ 6.7 $1.2 $ -- $ (4.3) $ 3.6
Environmental....................... 15.7 .7 26.5 (4.2) 38.7
Litigation.......................... 10.9 -- 20.0 (2.2) 28.7
Other(a)............................ 19.5 -- 2.6 (3.5) 18.6
----- ---- ----- ------ -----
$52.8 $1.9 $49.1 $(14.2) $89.6
DECEMBER 31, 1999:
Allowance for doubtful accounts..... $ 1.1 $ -- $ 5.6 $ -- $ 6.7
Environmental....................... 5.8 -- 63.0 (53.1) 15.7
Litigation.......................... -- -- 11.0 (0.1) 10.9
Other(a)............................ 11.3 -- 17.0 (8.8) 19.5
----- ---- ----- ------ -----
$18.2 $ -- $96.6 $(62.0) $52.8
</Table>

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

(a) Principally consists of other contingency reserves which are included in
the "Other Current Liabilities" or "Other Long Term Liabilities".

(b) Principally consists of environmental, litigation and other contingency
reserves assumed in business acquisitions and combinations.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Members of
Duke Energy Field Services, LLC

We have audited the accompanying consolidated balance sheets of Duke Energy
Field Services, LLC and subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of income, comprehensive income, members'
equity, and cash flows for each of the three years in the period ended December
31, 2001. Our audits also included the financial statement schedule listed in
the Index at Item 14. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 consolidated financial statements present fairly, in
all material respects, the financial position of Duke Energy Field Services, LLC
and subsidiaries at December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.

As discussed in Note 2 to the Consolidated Financial Statements, in 2001
the Company changed its method of accounting for derivative instruments and
hedging activities to conform to Statement of Financial Accounting Standards No.
133.

DELOITTE & TOUCHE LLP

Denver, Colorado
March 1, 2002

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

<Table>
<Caption>
NAME AGE POSITION
- ---- --- --------

Jim W. Mogg.................... 53 Director and Chairman of the Board, President and
Chief Executive Officer
Mark A. Borer.................. 47 Senior Vice President, Southern Division
Michael J. Bradley............. 47 Senior Vice President, Northern Division
Robert F. Martinovich.......... 44 Senior Vice President, Western Division
Rose M. Robeson................ 41 Vice President and Chief Financial Officer
Brent L. Backes................ 42 Vice President, General Counsel and Secretary
William W. Slaughter........... 54 Executive Vice President
Fred J. Fowler................. 56 Director
John E. Lowe................... 43 Director
Michael J. Panatier............ 53 Director
Richard B. Priory.............. 55 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, Vice Chairman and Chairman of the Audit Committee of the general
partner of TEPPCO. Mr. Mogg has been in the energy industry since 1973.

Mark A. Borer is Senior Vice President, Southern Division 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 is also a director
of the general partner of TEPPCO. Mr. Borer has been in the energy industry
since 1978.

Michael J. Bradley is Senior Vice President, Northern Division 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 Division 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, Oklahoma Region for GPM Gas Corporation, and
from 1994 until 1996, he was Business Development Manager for GPM Gas
Corporation. Mr. Martinovich has been in the energy industry since 1980.

Rose M. Robeson was named Vice President and Chief Financial Officer of our
company effective January 29, 2002. Ms. Robeson joined the Company on May 1,
2000 as Vice President and Treasurer. She was previously Vice President and
Treasurer of Kinder Morgan, Inc. (formerly KN Energy, Inc.) from April 1998 to
April 2000 and Assistant Treasurer of Kinder Morgan, Inc. from August 1996 to
April 1998. Ms. Robeson has been in the energy industry since 1987.

Brent L. Backes is Vice President, General Counsel and Secretary of our
company effective January 29, 2002. Mr. Backes joined the Predecessor Company in
April 1998 as Senior Attorney. He was previously Senior Associate Attorney at
LeBoeuf, Lamb, Greene & MacRae, LLP. Mr. Backes has been in the energy industry
since 1998.

William W. 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 PanEnergy and President of
PanEnergy International Development Corporation. Mr. Slaughter is also a
director of the general partner of TEPPCO. Mr. Slaughter has been in the energy
industry since 1970.

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
Corporation. Mr. Fowler is also a director of the general partner of TEPPCO. Mr.
Fowler has been in the energy industry since 1968.

John E. Lowe, a Director of our company, is the Senior Vice President of
Corporate Strategy and Development of Phillips, and has held that position since
2001. Mr. Lowe previously served as Senior Vice President of Planning and
Strategic Transactions of Phillips from 2000 to 2001 and as Vice President of
Planning and Strategic Transactions of Phillips from 1999 to 2000. From 1997 to
1999, Mr. Lowe served as Supply Chain Manager for Refining, Marketing and
Transportation of Phillips. From 1993 to 1997 he served as either Director or
Manager of Finance for Phillips. Mr. Lowe has been in the energy industry since
1981.

Michael J. Panatier, a Director of our company, is the Executive Vice
President of Refining, Marketing and Transportation of Phillips, and has held
that position since 2001. Mr. Panatier previously served as Vice Chairman of our
Company from the Combination until 2001. 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.

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 is also a director of Dana Corporation and US Airways
Group, Inc. Mr. Priory has been in the energy industry since 1976.

Pursuant to our limited liability company agreement, we have five directors
two of which are appointed by Phillips and three of which are appointed by Duke
Energy.

There are no family relationships between any of the executive officers nor
any arrangement or understanding between any executive officer and any other
person pursuant to which the officer was selected.

ITEM 11. EXECUTIVE COMPENSATION

The following table sets forth compensation information for the years ended
December 31, 2000 and December 31, 2001 for the Chief Executive Officer and each
of our next four most highly compensated executive officers. These five
individuals are referred to as the "Named Executive Officers."

<Table>
<Caption>
LONG TERM COMPENSATION
----------------------------------
ANNUAL COMPENSATION SECURITIES
-------------------------------- RESTRICTED UNDERLYING
OTHER ANNUAL STOCK STOCK LTIP ALL OTHER
SALARY BONUS COMPENSATION AWARDS OPTIONS PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($)(4) ($)(5) ($)(6) (#)(12) ($) ($)(13)
- --------------------------- ---- ------- ------- ------------ ---------- ---------- ------- ------------

Jim W. Mogg(1)............... 2001 419,231 201,482 -- 337,990(7) 74,800 -- 91,825
Chairman of the Board, 2000 376,474 475,219 -- 193,513 133,000 76,102 37,399
President and Chief
Executive Officer
Mark A. Borer(1)............. 2001 219,230 65,500 -- 116,431(8) 25,800 -- 39,457
Senior Vice President, 2000 196,154 166,300 -- 145,730 33,600 -- 24,497
Southern Division
Michael J. Bradley(1)........ 2001.. 219,230 61,800 -- 116,431(9) 25,800 -- 27,587
Senior Vice President, 2000 196,154 169,400 -- 145,730 34,400 52,553 19,277
Northern Division
Robert F. Martinovich(2)..... 2001.. 219,230 55,800 -- 116,431(10) 25,800 -- 38,632
Senior Vice President, 2000 190,797 160,400 -- 145,730 33,600 -- 54,507
Western Division
Martha B. Wyrsch(1)(3)....... 2001.. 192,500 53,323 -- 94,163(11) 21,000 -- 22,256
Senior Vice President, 2000 171,500 165,043 -- 50,127 19,320 -- 12,525
General Counsel and
Secretary
</Table>

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

(1) Prior to the Combination on March 31, 2000 all compensation paid to Messrs.
Mogg, Borer and Bradley and Ms. Wyrsch was paid by Duke Energy and was
attributable to services provided to the Predecessor Company.

(2) Prior to the Combination on March 31, 2000 all compensation paid to Mr.
Martinovich was paid by Phillips.

(3) During the years covered by this table, Ms. Wyrsch also provided services
to Duke Energy as Senior Vice President and General Counsel Energy
Transmission. During these time periods, the Company was responsible for
70% of Ms. Wyrsch's compensation and Duke Energy was responsible for the
remaining 30% of such compensation, except for bonuses which were paid
based in part by the performance of each company. The compensation for Ms.
Wyrsch reflected in this table consists of the 70% of her compensation that
was paid by the Company for services she provided to the Company, except
for the bonus, which was paid based on the Company's performance. In 2001,
Ms. Wyrsch's combined total salary, bonus, restricted stock award, stock
option award and all other compensation for her services to both the
Company and Duke Energy were the following respectively: $275,000,
$135,852, $134,518, 30,000, and $31,793. In 2000, Ms. Wyrsch's combined
total salary, bonus, restricted stock award, stock option award and all
other compensation for her services to both the Company and Duke Energy
were the following respectively: $245,000, $235,775, $71,610, 27,600 and
$17,893.

(4) Messrs. Mogg, Borer, Bradley and Ms. Wyrsch elected to forego a portion of
their 2001 cash bonus for Duke Energy stock options under the Duke Energy
Short Term Incentive Exchange Program as follows: Mr. Mogg, $40,296 for
7,500 option shares; Mr. Borer, $32,750 for 6,100 option shares; Mr.
Bradley $12,360 for 2,300 option shares; and Ms. Wyrsch, $13,585 for 2,500
option shares. The awards were granted under the Duke Energy 1998 Long Term
Incentive Plan on January 17, 2002 at the fair market value on that date of
$38.33, as provided under that Plan. The number of option shares awarded is
calculated by dividing the foregone bonus amount by 50% of the present
value of a share of Duke Energy Common Stock on the date of grant. The
options were 100% vested at grant. These stock options will be reported in
next year's Annual Report on Form 10-K.

(5) 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.

(6) Messrs. Mogg, Borer, Bradley and Martinovich and Ms. Wyrsch elected to
receive a portion of the value of their long term incentive component of
their 2002 compensation in the form of phantom stock. The awards were
granted under the Duke Energy 1998 Long Term Incentive Plan on December 19,
2001. Phantom stock is represented by units denominated in shares of Duke
Energy common stock. Each phantom stock unit represents the right to
receive, upon vesting, one share of Duke Energy common stock. One quarter
of each award vests on each of the first four anniversaries of the grant
date provided the recipient continues to be employed by the Company or his
or her employment terminates on account of retirement. The awards fully
vest in the event of the recipient's death or disability or a change in
control as specified in the Plan. If the recipient's employment terminates
other than on account of retirement, death or disability, any unvested
shares remaining on the termination date are forfeited. The phantom stock
awards also grant an equal number of dividend equivalents, which represent
the right to receive cash payments equivalent to the cash dividends paid on
the number of shares of Duke Energy common stock represented by the phantom
stock units awarded, until the related phantom stock units vest or are
forfeited.

The aggregate number of phantom stock units held by Messrs. Mogg, Borer,
Bradley and Martinovich and Ms. Wyrsch at December 31, 2001 and their
values on that date are as follows:

<Table>
<Caption>
NUMBER OF VALUE AT
PHANTOM STOCK DECEMBER 31,
UNITS 2001
------------- ------------

J. Mogg.................................... 12,360 $485,254
M. Borer................................... 3,930 154,292
M. Bradley................................. 3,930 154,292
R. Martinovich............................. 3,930 154,292
M. Wyrsch.................................. 4,830 189,626
</Table>

(7) In addition to the 12,360 phantom stock units in note 6, at December 31,
2001, Mr. Mogg held an aggregate of 36,000 restricted shares of Duke Energy
common stock having a value of $1,413,360. Dividends are paid on such
shares. The vesting of these shares is determined by, among other things,
the performance of Duke Energy.

(8) In addition to the 3,930 phantom stock units in note 6, at December 31,
2001, Mr. Borer held an aggregate of 5,390 restricted shares of Duke Energy
common stock having a value of $211,611. Dividends are paid on such shares.
Of these restricted shares, 2,000 will vest on April 1, 2002 and 3,390 will
vest on May 26, 2003.

(9) In addition to the 3,930 phantom stock units in note 6, at December 31,
2001, Mr. Bradley held an aggregate of 3,390 restricted shares of Duke
Energy common stock having a value of $133,091. Dividends are paid on such
shares. These shares will vest on May 26, 2002.

(10) In addition to the 3,930 phantom stock units in note 6, at December 31,
2001, Mr. Martinovich held an aggregate of 1,695 restricted shares of Duke
Energy common stock having a value of $66,546. Dividends are paid on such
shares. One half of these shares will vest on May 26, 2002.

(11) In addition to the 4,830 phantom stock units in note 6, at December 31,
2001, Ms. Wyrsch held an aggregate of 6,516 restricted shares of Duke
Energy common stock having a value of $255,818. Dividends are paid on such
shares. Of these restricted shares, 2,916 will vest on May 26, 2003 and
1,200 will vest on the next three anniversaries of October 1. The vesting
of these shares is determined by, among other things, the performance of
Duke Energy.

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

(13) Represents the following for 2001:

- Matching contributions under the Company's 401(k) and Retirement Plan as
follows: J. Mogg, $17,200; M. Borer, $17,200; M. Bradley, $17,200; R.
Martinovich, $17,200; M. Wyrsch, $7,140.

- Make-whole contributions under the Company's Executive Deferred
Compensation Plan as follows: J. Mogg, $72,445; M. Borer, $21,553; M.
Bradley, $9,683; R. Martinovich, $20,963; M. Wyrsch, $14,312.

- Life Insurance premiums paid by the Company as follows: J. Mogg, $2,180;
M. Borer, $704; M. Bradley, $704; R. Martinovich, $469; M. Wyrsch, $803.

BOARD COMPENSATION

Our Directors do not receive a retainer or fees for service on our Board of
Directors or any committees. 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.

CONSULTING AGREEMENT

We have entered into a contract for consulting services with Mr. Slaughter
that terminates in June 2002. During the term of this contract, Mr. Slaughter
receives a quarterly retainer of $46,860, in exchange for which Mr. Slaughter
has agreed to perform services for us for up to 30 days per quarter. If Mr.
Slaughter works more than 30 days per quarter, he is entitled to additional
compensation at the rate of $1,562 for each additional day. For the year ended
December 31, 2001, the Company paid Mr. Slaughter $356,136 under this
arrangement. In addition, under the terms of the contract, Mr. Slaughter
receives a long term incentive award that tracks the performance of Duke Energy
common stock. The award, valued at $360,000 at the time of grant, is paid in
cash, 50% on each of the first and second anniversary of grant. Any unpaid
portion of such award will automatically be converted into stock options and
restricted stock in the event of an initial public offering of equity securities
occurring before the payment date.

OPTION GRANTS IN LAST FISCAL YEAR

None of the Named Executive Officers has received options to purchase
members interests in our company. None of the Named Executive Officers held
options to purchase member interests in our company at December 31, 2001.

This table shows options granted of Duke Energy common stock to the Named
Executive Officers during 2001, along with the present value of the options on
the date they were granted, calculated as described in footnote 2 to the table.

OPTION/SAR GRANTS IN LAST FISCAL YEAR

<Table>
<Caption>
INDIVIDUAL GRANTS
--------------------------------------------------------------------
NUMBER OF SHARES % OF TOTAL
UNDERLYING OPTIONS/SARS
OPTIONS/SARS GRANTED TO EXERCISE OR BASE GRANT DATE PRESENT
NAME GRANTED(1)(#) EMPLOYEES(2) PRICE ($/SH) EXPIRATION DATE VALUE(3)($)
- ---- ---------------- ------------ ---------------- --------------- ------------------

J. W. Mogg........... 74,800 --(4) 37.68 12/19/2011 786,896
M. A. Borer.......... 25,800 --(4) 37.68 12/19/2011 271,416
M. J. Bradley........ 25,800 --(4) 37.68 12/19/2011 271,416
R. F. Martinovich.... 25,800 --(4) 37.68 12/19/2011 271,416
M. B. Wyrsch......... 30,000 --(4) 37.68 12/19/2011 315,600
</Table>

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

(1) Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons.

(2) Reflects percentage that the grant represents of the total options granted
to employees of Duke Energy and its subsidiaries during 2001.

(3) Based on the Black-Scholes option valuation model. The following table lists
key input variables used in valuing the options:

<Table>
<Caption>
INPUT VARIABLE:
---------------

Risk-free Interest Rate..................................... 5.23%
Dividend Yield.............................................. 3.37%
Stock Price Volatility...................................... 29.71%
Option Term................................................. 10 years
</Table>

With respect to all option grants listed in the table, the volatility
variable reflected historical monthly stock price trading date from
November 30, 1998 through November 30, 2001. An adjustment was made with
respect to each valuation for a risk of forfeiture during the vesting
period. The actual value, if any, that a grantee may realized will depend
on the excess of the stock price over the exercise price on the date the
option is exercised, so that there is no assurance the value realized will
be at or near the value estimated based upon the Black-Scholes option
valuation model.

(4) less than one percent.

OPTION EXERCISES AND YEAR-END VALUES

This tables shows aggregate exercises of options for Duke Energy common
stock during 2001 by the Named Executive Officers, and the aggregate year-end
value of the unexercised options held by them. The value assigned to each
unexercised "in-the-money" stock option is based on the positive spread between
the exercise price of the stock option and the fair market value of Duke Energy
common stock on December 31, 2001, which was $39.65. The fair market value is
the average of the high and low prices of a share of Duke Energy common stock on
that date as reported on the New York Stock Exchange Composite Transactions
Tape. The ultimate value of a stock option will depend on the market value of
the underlying shares on a future date.

AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUES

<Table>
<Caption>
NUMBER OF
SECURITIES
UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS/SARS AT OPTIONS/SARS AT
FY-END*(#) FY-END($)
--------------- --------------------
SHARES ACQUIRED EXERCISABLE/ EXERCISABLE/
NAME ON EXERCISE(#) VALUE REALIZED($) UNEXERCISABLE UNEXERCISABLE
- ---- --------------- ----------------- --------------- --------------------

J. W. Mogg........... 1,180 36,827 113,854/218,634 1,200,952/1,160,106
M. A. Borer.......... 5,000 77,791 16,450/56,550 165,142/274,999
M. J. Bradley........ 13,981 249,840 11,899/60,050 147,052/301,592
R. F. Martinovich.... 10,650/51,750 60,900/172,626
M. B. Wyrsch......... 33,700/77,500 372,083/431,183
</Table>

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

* Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information regarding the beneficial
ownership of the member interests in our company by:

- each holder of more than 5% of our member interests;

- the Named Executive Officers;

- each director; and

- all directors and executive officers as a group.

<Table>
<Caption>
NAME OF BENEFICIAL OWNERS BENEFICIAL OWNERSHIP
- ------------------------- --------------------

Duke Energy Corporation..................................... 69.7%
526 South Church Street
Charlotte, North Carolina 28201-1006
Phillips Petroleum Company.................................. 30.3
Phillips Building
Bartlesville, Oklahoma 74004
Jim W. Mogg................................................. --
Mark A. Borer............................................... --
Michael J. Bradley.......................................... --
Robert F. Martinovich....................................... --
Martha B. Wyrsch............................................ --
Fred J. Fowler.............................................. --
John E. Lowe................................................ --
Michael J. Panatier......................................... --
Richard B. Priory(1)........................................ 69.7
All directors and executive officers as a group (11
persons)(1)............................................... 69.7%
</Table>

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

(1) Mr. Priory serves as Chairman, President and Chief Executive Officer of Duke
Energy. As such, Mr. Priory may be deemed to have voting and dispositive
power over our member interests beneficially owned by Duke Energy. Mr.
Priory disclaims beneficial ownership of the securities owned by Duke
Energy.

In August 2000, we issued $300.0 million of preferred member interests to
affiliates of Duke Energy and Phillips. Duke Energy Field Services Investment
Corp. was issued a preferred member interest representing 69.7% of the
outstanding preferred member interests in our company and Phillips Gas
Investment Company was issued a preferred member interest representing a 30.3%
of the outstanding preferred member interests in our company. See Note 11 to the
Notes to Consolidated Financial Statements. The preferred member interests have
no voting rights in the election of our directors. Duke Energy and Mr. Priory
may be deemed to have dispositive power over the preferred member interest held
by Duke Energy Field Services Investment Corp., and Phillips may be deemed to
have dispositive power over the preferred member interest held by Phillips Gas
Investment Company. Mr. Priory disclaims beneficial ownership of the preferred
member interests held by Duke Energy Field Services Investment Corp.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On March 31, 2000, we combined the midstream natural gas businesses of Duke
Energy and Phillips. In connection with the Combination, Duke Energy and
Phillips transferred all of their respective interests in their subsidiaries
that conducted their midstream natural gas business to us. In connection with
the Combination, Duke Energy and Phillips also transferred to us additional
midstream natural gas assets acquired by Duke Energy or Phillips prior to
consummation of the Combination, including the Mid-Continent gathering and
processing assets of Conoco and Mitchell Energy. In addition, concurrently with
the Combination, we obtained by transfer from Duke Energy the general partner of
TEPPCO. In exchange for the asset contributions, Phillips received 30.3% of the
outstanding non-preferred member interests in our company, with Duke Energy
holding the remaining 69.7% of the outstanding non-preferred member interests in
our company. In connection with the closing of the Combination, we borrowed
approximately $2.8 billion in the commercial paper market and made one-time cash
distributions (including reimbursements for acquisitions) of approximately $1.5
billion to Duke Energy and approximately $1.2 billion to Phillips.

There are significant transactions and relationships between us, Duke
Energy and Phillips. For purposes of governing these ongoing relationships and
transactions, we will 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. 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, dated as of March 14, 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, insurance, cash management, ad valorem taxes, treasury, media
relations, printing, records management, legal functions and shareholder
services. These services are priced on the basis of a monthly charge
approximating market prices. Additionally, we may use other Duke Energy services
subject to hourly rates, including legal, insurance, internal audit, tax
planning, human resources and security departments. This agreement, as amended,
expires on December 31, 2002. We believe that the overall charges under this
agreement will not exceed charges we would have incurred had we obtained similar
services from outside sources.

LICENSE AGREEMENT

In connection with the Combination, Duke Energy has licensed to us a
non-exclusive right to use the phrase "Duke Energy" and its logo and certain
other trademarks 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 and other
materials bearing a name, phrase or logo incorporating "Duke."

OTHER TRANSACTIONS

Prior to the Combination, Duke Energy and its subsidiaries engaged in a
number of transactions with the Predecessor Company. This included sales of
residue gas and NGLs, the purchase of raw natural gas and other petroleum
products and providing natural gas gathering and transportation services to Duke
Energy and its subsidiaries. We anticipate that we will continue to engage is
such activities with Duke Energy and its subsidiaries in the ordinary course of
business. In 2001, our total revenues from such activities with Duke Energy and
its subsidiaries were approximately $1,648.5 million.

TRANSACTIONS WITH PHILLIPS

Prior to the Combination, Phillips engaged in a number of transactions with
GPM Gas Corporation, the subsidiary of Phillips that owned its midstream natural
gas assets that were transferred to us as part of the Combination. This included
the sale of residue gas, NGLs and sulfur, and the purchase of raw natural gas.
In addition, it included a long term agreement with Phillips, and subsequently
Chevron Phillips Chemical Company LLC ("CPChem"), for the sale of NGLs at
index-based prices. We anticipate that we will continue to engage in such
activities with Phillips and its subsidiaries and CPChem in the ordinary course
of business. For the year ended December 31, 2001, our total revenues from such
activities with Phillips and its subsidiaries, and CPChem were approximately
$816.2 million.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Consolidated Financial Statements, Supplemental Financial Data and
Supplemental Schedule included in Part II of this annual report are as follows:

Consolidated Financial Statements

Consolidated Statements of Income for the Years Ended December 31, 2001,
2000 and 1999
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2001, 2000 and 1999
Consolidated Statements of Cash Flows for the Years Ended December 31,
2001, 2000 and 1999
Consolidated Balance Sheets as of December 31, 2001 and 2000
Consolidated Statements of Members' Equity for the Years Ended December
31, 2001, 2000 and 1999

Notes to Consolidated Financial Statements

Quarterly Financial Data (unaudited) (included in Note 18 of the Notes to
Consolidated Financial Statements)

Consolidated Financial Statement Schedule II -- Valuation and Qualifying
Accounts and Reserves for the Years Ended December 31, 2001, 2000 and 1999

All other schedules are omitted because of the absence of the conditions
under which they are required or because the required information is included in
the financial statements or notes thereto.

(b) Reports on Form 8-K

A current report on Form 8-K was filed on November 9, 2001 under Item 5,
Other Events and under Item 7, Financial Statements and Disclosures.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

DUKE ENERGY FIELD SERVICES, LLC

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

March 27, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.

<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----

/s/ JIM W. MOGG Chairman of the Board, President March 27, 2002
------------------------------------------------ and Chief Executive Officer
Jim W. Mogg (Principal Executive Officer)

/s/ ROSE M. ROBESON Chief Financial Officer (Principal March 27, 2002
------------------------------------------------ Financial and Accounting Officer)
Rose M. Robeson

/s/ FRED J. FOWLER Director March 27, 2002
------------------------------------------------
Fred J. Fowler

/s/ JOHN E. LOWE Director March 27, 2002
------------------------------------------------
John E. Lowe

/s/ MICHAEL J. PANATIER Director March 27, 2002
------------------------------------------------
Michael J. Panatier

/s/ RICHARD B. PRIORY Director March 27, 2002
------------------------------------------------
Richard B. Priory
</Table>

EXHIBIT INDEX

Exhibits filed herewith are designated by an asterisk(*). All exhibits not
so designated are incorporated by reference to a prior filing, as indicated.
Items constituting management contracts or compensatory plans or arrangements
are designated by a double asterisk (**).

<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------

3.1 -- Amended and Restated Limited Liability Company Agreement of
Duke Energy Field Services, LLC by and between Phillips Gas
Company and Duke Energy Field Services Corporation, dated as
of March 31, 2000 (incorporated by reference to Exhibit 3.1
to Form 10 (Registration No. 000-31095) of registrant filed
on July 20, 2000).
3.2 -- First Amendment to Amended and Restated Limited Liability
Company Agreement of Duke Energy Field Services, LLC dated
as of August 4, 2000 (incorporated by reference to Exhibit
3.1 to Current Report on Form 8-K of registrant filed on
August 16, 2000).
4.1 -- Form of Indenture (incorporated by reference to Exhibit 4.1
to Registration Statement on Form S-3/A (Registration No.
333-41854) of registrant filed on August 2, 2000).
4.2 -- First Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of August 16, 2000 (incorporated by reference to
Exhibit 4.1 to Current Report on Form 8-K of registrant
filed on August 16, 2000).
4.3 -- Second Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of February 2, 2001 (incorporated by reference to
Exhibit 4.1 to Current Report on Form 8-K of registrant
filed on February 1, 2001).
*4.4 -- Third Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of November 9, 2001.
10.1 -- Second Amendment to Parent Company Agreement among Phillips
Petroleum Company, Duke Energy Corporation, Duke Energy
Field Services, LLC and Duke Energy Field Services
Corporation dated as of August 4, 2000 (incorporated by
reference to Exhibit 10.1 to Current Report on Form 8-K of
registrant filed on August 16, 2000).
10.2** -- Employment Agreement dated as of April 1, 2000 between Duke
Energy Field Services Assets, LLC and Michael J. Panatier
(incorporated by reference to Exhibit 10.1 to Registration
Statement on Form S-1/A (Registration No. 333-32502) of Duke
Energy Field Services Corporation, filed on May 4, 2000).
10.3** -- First Amendment to Employment Agreement dated as of June 28,
2000 between Duke Energy Field Services Assets, LLC and
Michael J. Panatier (incorporated by reference to Exhibit
10.1(b) to Form 10/A (Registration No. 000-31095) of
registrant filed on August 2, 2000).
10.4 -- 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
(incorporated by reference to Exhibit 10.3 to Registration
Statement on Form S-1/A (Registration No. 333-32502) of Duke
Energy Field Services Corporation, filed on March 27, 2000).
10.5 -- First Amendment to Services Agreement dated as of December
15, 2000 between Duke Energy Corporation, Duke Energy
Business Services, LLC, Pan Service Company, Duke Energy Gas
Transmission Corporation and Duke Energy Field Services,
LLC. (incorporated by reference to Exhibit 10.5 to Annual
Report on Form 10-K of registrant filed on March 30, 2001).
10.6 -- Transition Services Agreement dated as of March 17, 2000
among Phillips Petroleum Company and Duke Energy Field
Services, LLC (incorporated by reference to Exhibit 10.4 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation, filed
on March 27, 2000).
10.7 -- Trademark License Agreement dated as of March 31, 2000 among
Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 10.5 to Registration
Statement on Form S-1/A (Registration No. 333-32502) of Duke
Energy Field Services Corporation, filed on May 4, 2000).
10.8 -- 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 on
December 30, 1999).
</Table>

<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------

10.9 -- First Amendment to Contribution and Governance Agreement
dated as of March 23, 2000 among Phillips Petroleum Company,
Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 10.7(b) to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation, filed
on March 27, 2000).
10.10 -- 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
(incorporated by reference to Exhibit 10.8 to Registration
Statement on Form S-1/A (Registration No. 333-32502) of Duke
Energy Field Services Corporation, filed on March 15, 2000).
10.11 -- Sulfur Sales Agreement effective as of January 1, 1999
between Phillips 66 Company, a division of Phillips
Petroleum Company, and GPM Gas Corporation (incorporated by
reference to Exhibit 10.9 to Registration Statement on Form
S-1/A (Registration No. 333-32502) of Duke Energy Field
Services Corporation, filed on March 27, 2000).
10.12 -- Parent Company Agreement dated as of March 31, 2000 among
Phillips Petroleum Company, Duke Energy Corporation, Duke
Energy Field Services, LLC and Duke Energy Field Services
Corporation (incorporated by reference to Exhibit 10.10 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation, filed
on May 4, 2000).
10.13 -- First Amendment to the Parent Company Agreement dated as of
May 25, 2000 among Phillips Petroleum Company, Duke Energy
Corporation, Duke Energy Field Services, LLC and Duke Energy
Field Services Corporation (incorporated by reference to
Exhibit 10.8(b) to Form 10 (Registration No. 333-41854) of
registrant filed on July 20, 2000).
10.14** -- Contract for Services dated as of April 1, 2000 between Duke
Energy Field Services Assets, LLC and William W. Slaughter
(incorporated by reference to Exhibit 10.11 to Registration
Statement on Form S-1/A (Registration No. 333-32502) of Duke
Energy Field Services Corporation, filed on May 4, 2000).
10.15** -- First Amendment to Contract for Services dated as of June
29, 2000 between Duke Energy Field Services Assets, LLC and
William W. Slaughter (incorporated by reference to Exhibit
10.9(b) to Form 10/A (Registration No. 333- 41854) of
registrant filed on August 2, 2000).
10.16 -- 364-Day Credit Facility among Duke Energy Field Services,
LLC,Duke Energy Field Services Corporation, Bank of America,
N.A., as Agent and the Lenders named therein, Dated March
31, 2001(incorporated by reference to Exhibit 10.1 to
Quarterly Report on Form 10-Q of registrant filed on August
13, 2001).
*12.1 -- Calculation of Ratio of Earnings to Fixed Charges.
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of Deloitte & Touche LLP.
</Table>