<Page>

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

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


                                    FORM 10-Q

                QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

FOR QUARTER ENDED SEPTEMBER 30, 2001              COMMISSION FILE NUMBER 0-31095


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


                     DELAWARE                               76-0632293
(State or other jurisdiction of incorporation) (IRS Employer Identification No.)


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


                                  303-595-3331
              (Registrant's telephone number, including area code)


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 and (2) has been subject to such filing requirements for
the past 90 days. Yes |X|No |_|

<Page>

                         DUKE ENERGY FIELD SERVICES, LLC
               FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2001

                                      INDEX

<Table>
<Caption>
ITEM                                                                            PAGE
----                                                                            ----
<S>                                                                             <C>

                    PART I. FINANCIAL INFORMATION (UNAUDITED)

1.  Financial Statements........................................................    1
       Consolidated Statements of Income for the Three and Nine Months
            Ended September 30, 2001 and 2000...................................    1
       Consolidated Statements of Comprehensive Income for the Three and
            Nine Months Ended September 30, 2001 and 2000.......................    2
       Consolidated Statements of Cash Flows for the Nine Months Ended
            September 30, 2001 and 2000.........................................    3
       Consolidated Balance Sheets as of September 30, 2001 and
            December 31, 2000...................................................    4
       Notes to Consolidated Financial Statements...............................    5
2.  Management's Discussion and Analysis of Financial Condition and
            Results of Operations...............................................   13
3.  Quantitative and Qualitative Disclosure about Market Risks..................   20

                           PART II. OTHER INFORMATION

1.  Legal Proceedings...........................................................   21
6.  Exhibits and Reports on Form 8-K............................................   21
    Signatures..................................................................   22
</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:

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

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

     o    level of creditworthiness of counterparties to transactions;

                                       i
<Page>

     o    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;

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

     o    weather and other natural phenomena;

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

     o    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

     o    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.

                                       ii
<Page>

                          PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

                         DUKE ENERGY FIELD SERVICES, LLC
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                                        THREE MONTHS ENDED,               NINE MONTHS ENDED,
                                                                           SEPTEMBER 30,                     SEPTEMBER 30,
                                                                   ----------------------------      ----------------------------
                                                                      2001             2000              2001             2000
                                                                   -----------      -----------      -----------      -----------
<S>                                                                <C>              <C>              <C>              <C>
OPERATING REVENUES:
   Sales of natural gas and petroleum products ...............     $   993,770      $ 2,117,698      $ 5,267,889      $ 5,122,552
   Sales of natural gas and petroleum products--affiliates ...         604,648          383,473        2,127,402          908,453
   Transportation, storage and processing ....................          82,709           43,315          202,233          135,774
   Transportation, storage and processing--affiliates ........              --            7,509               --            8,787
                                                                   -----------      -----------      -----------      -----------
           Total operating revenues ..........................       1,681,127        2,551,995        7,597,524        6,175,566
                                                                   -----------      -----------      -----------      -----------
COSTS AND EXPENSES:
   Natural gas and petroleum products ........................       1,201,409        2,050,936        5,895,617        5,046,801
   Natural gas and petroleum products--affiliates ............         161,851          150,059          680,247          269,231
   Operating and maintenance .................................          97,253           92,647          276,789          233,001
   Depreciation and amortization .............................          72,597           62,824          207,314          168,183
   General and administrative ................................          31,183           36,586           89,768           86,729
   General and administrative--affiliates ....................           2,097            5,659            8,959           25,492
   Net (gain) loss on sale of assets .........................              65              783             (923)           1,120
                                                                   -----------      -----------      -----------      -----------
           Total costs and expenses ..........................       1,566,455        2,399,494        7,157,771        5,830,557
                                                                   -----------      -----------      -----------      -----------
OPERATING INCOME .............................................         114,672          152,501          439,753          345,009
EQUITY IN EARNINGS OF
   UNCONSOLIDATED AFFILIATES .................................           6,544            4,308           22,624           19,015
INTEREST EXPENSE:
   Interest expense ..........................................          42,455           46,343          124,847           91,709
   Interest expense--affiliates ..............................              --               --               --           14,485
                                                                   -----------      -----------      -----------      -----------
           Total interest expense ............................          42,455           46,343          124,847          106,194
                                                                   -----------      -----------      -----------      -----------
INCOME BEFORE INCOME TAXES ...................................          78,761          110,466          337,530          257,830
INCOME TAX EXPENSE (BENEFIT) .................................             (75)          (3,838)             263         (310,603)
                                                                   -----------      -----------      -----------      -----------
INCOME BEFORE CUMULATIVE EFFECT OF
   CHANGE IN ACCOUNTING PRINCIPLE ............................          78,836          114,304          337,267          568,433
CUMULATIVE EFFECT OF CHANGE IN
   ACCOUNTING PRINCIPLE, NET OF TAX ..........................              --               --              411               --
                                                                   -----------      -----------      -----------      -----------
NET INCOME ...................................................          78,836          114,304          336,856          568,433
DIVIDENDS ON PREFERRED MEMBERS' INTEREST .....................           7,125            4,592           21,375            4,592
                                                                   -----------      -----------      -----------      -----------
EARNINGS AVAILABLE FOR MEMBERS' INTEREST .....................     $    71,711      $   109,712      $   315,481      $   563,841
                                                                   ===========      ===========      ===========      ===========
</Table>

                 See Notes to Consolidated Financial Statements.

                                       1
<Page>

                         DUKE ENERGY FIELD SERVICES, LLC
                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                   (UNAUDITED)
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                                         THREE MONTHS ENDED,            NINE MONTHS ENDED,
                                                                            SEPTEMBER 30,                 SEPTEMBER 30,
                                                                     --------------------------    --------------------------
                                                                        2001           2000            2001           2000
                                                                     -----------    -----------    -----------    -----------
<S>                                                                  <C>            <C>            <C>            <C>
NET INCOME .....................................................     $  78,836      $ 114,304      $ 336,856      $ 568,433

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
   Cumulative effect of change in accounting principle .........            --             --          6,626             --
   Foreign currency translation adjustment .....................        (4,804)        (1,287)        (2,657)        (2,980)
   Net unrealized gains on cash flow hedges ....................        14,955             --          3,619             --
   Reclassification into earnings ..............................        (5,860)            --          9,081             --
                                                                     ---------      ---------      ---------      ---------
          Total other comprehensive income (loss), net of tax ..         4,291         (1,287)        16,669         (2,980)
                                                                     ---------      ---------      ---------      ---------
TOTAL COMPREHENSIVE INCOME .....................................     $  83,127      $ 113,017      $ 353,525      $ 565,453
                                                                     =========      =========      =========      =========
</Table>

                 See Notes to Consolidated Financial Statements.


                                       2
<Page>

                         DUKE ENERGY FIELD SERVICES, LLC
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                                                          NINE MONTHS ENDED,
                                                                                              SEPTEMBER 30,
                                                                                      ----------------------------
                                                                                         2001              2000
                                                                                      -----------      -----------
<S>                                                                                   <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
   Net income ...................................................................     $   336,856      $   568,433
   Adjustments to reconcile net income to net cash provided by
       operating activities:
       Depreciation and amortization ............................................         207,314          168,183
       Deferred income taxes ....................................................              --         (302,778)
       Change in derivative fair value ..........................................          (4,447)              --
       Equity in earnings of unconsolidated affiliates ..........................         (22,624)         (19,015)
       Loss (gain) on sale of assets ............................................            (923)           1,120
   Change in operating assets and liabilities (net of effects of acquisitions)
       which provided (used) cash:
       Accounts receivable ......................................................          45,789         (149,848)
       Accounts receivable--affiliates ..........................................          77,767          (78,552)
       Inventories ..............................................................          48,843          (77,702)
       Unrealized gains on mark-to-market transactions ..........................         (82,328)         (42,161)
       Other current assets .....................................................          (1,273)          40,319
       Other noncurrent assets ..................................................         (23,492)          (6,285)
       Accounts payable .........................................................        (184,577)         427,194
       Accounts payable--affiliates .............................................         (47,532)          (2,186)
       Accrued interest payable .................................................         (31,375)          16,547
       Unrealized losses on mark-to-market transactions .........................          52,291           48,233
       Other current liabilities ................................................         (11,826)          38,078
       Other long term liabilities ..............................................         (22,065)         (17,708)
                                                                                      -----------      -----------
           Net cash provided by operating activities ............................         336,398          611,872
                                                                                      -----------      -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
   Acquisitions and other capital expenditures ..................................        (448,043)        (264,105)
   Investment expenditures ......................................................          (1,114)          (3,605)
   Investment distributions .....................................................          31,609           19,225
   Proceeds from sales of assets ................................................          20,931            6,928
                                                                                      -----------      -----------
           Net cash used in investing activities ................................        (396,617)        (241,557)
                                                                                      -----------      -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
   Net change in advances--parents ..............................................          (2,182)         (55,509)
   Distributions to parents .....................................................        (234,909)      (2,744,319)
   Proceeds from issuing preferred members' interest ............................              --          300,000
   Proceeds from issuing debt ...................................................         248,358        1,687,564
   Payment of debt ..............................................................         (49,281)              --
   Short-term debt--net .........................................................         100,663          442,888
                                                                                      -----------      -----------
           Net cash provided by (used in) financing activities ..................          62,649         (369,376)
                                                                                      -----------      -----------
NET INCREASE IN CASH AND CASH EQUIVALENTS .......................................           2,430              939
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ..................................           1,553              792
                                                                                      -----------      -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD ........................................     $     3,983      $     1,731
                                                                                      ===========      ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
   INFORMATION - Cash paid for interest (net of amounts capitalized) ............     $   152,597      $    86,956
</Table>

                 See Notes to Consolidated Financial Statements.

                                       3
<Page>

                         DUKE ENERGY FIELD SERVICES, LLC
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                                 SEPTEMBER 30,   DECEMBER 31,
                                                                     2001           2000
                                                                 -------------   ------------
                                     ASSETS
<S>                                                              <C>             <C>
CURRENT ASSETS:
   Cash and cash equivalents ...............................     $     3,983     $     1,553
   Accounts receivable:
       Customers, net ......................................         481,319         725,379
       Affiliates ..........................................         175,510         253,277
       Other ...............................................         286,210          67,316
   Inventories .............................................          40,753          83,325
   Unrealized gains on trading and hedging transactions ....         143,983          46,185
   Other ...................................................          12,998          14,275
                                                                 -----------     -----------
           Total current assets ............................       1,144,756       1,191,310
                                                                 -----------     -----------
PROPERTY, PLANT AND EQUIPMENT, NET .........................       4,708,161       4,152,480
INVESTMENT IN AFFILIATES ...................................         142,823         261,551
INTANGIBLE ASSETS:
   Natural gas liquids sales contracts, net ................          97,247          97,956
   Goodwill, net ...........................................         378,911         376,195
                                                                 -----------     -----------
           Total intangible assets .........................         476,158         474,151
                                                                 -----------     -----------
UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS .......          18,647              --
OTHER NONCURRENT ASSETS ....................................          98,751          90,606
                                                                 -----------     -----------
TOTAL ASSETS ...............................................     $ 6,589,296     $ 6,170,098
                                                                 ===========     ===========

                        LIABILITIES AND MEMBERS' EQUITY

CURRENT LIABILITIES:
   Accounts payable:
       Trade ...............................................     $   557,750     $   915,130
       Affiliates ..........................................          13,932          61,464
       Other ...............................................         229,457          41,322
   Short term debt .........................................         447,073         346,410
   Unrealized losses on trading and hedging transactions ...         102,536          51,179
   Accrued interest payable ................................          18,235          49,641
   Accrued taxes other than income .........................          22,212          21,717
   Distributions payable to members ........................           7,780         127,561
   Other ...................................................         114,462         114,408
                                                                 -----------     -----------
           Total current liabilities .......................       1,513,437       1,728,832
                                                                 -----------     -----------
DEFERRED INCOME TAXES ......................................          25,068              --
LONG-TERM DEBT .............................................       1,941,090       1,688,157
UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS ......          11,279              --
OTHER LONG TERM LIABILITIES ................................          27,643          32,274
MINORITY INTEREST ..........................................         125,795              --
PREFERRED MEMBERS' INTEREST ................................         300,000         300,000
COMMITMENTS AND CONTINGENT LIABILITIES (Note 6)
MEMBERS' EQUITY:
   Members' interest .......................................       1,709,290       1,709,290
   Retained earnings .......................................         921,454         713,974
   Accumulated other comprehensive income (loss) ...........          14,240          (2,429)
                                                                 -----------     -----------
           Total members' equity ...........................       2,644,984       2,420,835
                                                                 -----------     -----------
TOTAL LIABILITIES AND MEMBERS' EQUITY ......................     $ 6,589,296     $ 6,170,098
                                                                 ===========     ===========
</Table>

                 See Notes to Consolidated Financial Statements.

                                       4
<Page>

                         DUKE ENERGY FIELD SERVICES, LLC
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (UNAUDITED)

1.   GENERAL

     Duke Energy Field Services, LLC (with its consolidated subsidiaries "the
Company") 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.

2.   ACCOUNTING POLICIES

     CONSOLIDATION - The Consolidated Financial Statements include the accounts
of all majority-owned subsidiaries after the elimination of significant
intercompany transactions and balances. These Consolidated Financial Statements
reflect all normal recurring adjustments that are, in the opinion of management,
necessary to present fairly the financial position and results of operations for
the respective periods.

     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, as
appropriate. On the date the swaps, futures or option contracts are entered
into, the Company designates the derivative as either held for trading (trading
instruments), a hedge of a recognized asset, liability or firm commitment (fair
value hedges), a hedge of a forecasted transaction or future cash flows (cash
flow hedges) or as a normal purchase or sale contract.

     The Company also formally assesses, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging transactions are
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.

     Commodity Trading - Prior to the settlement of any derivative contract held
for trading purposes, a favorable or unfavorable price movement is reported as
Natural Gas and Petroleum Products Purchases 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 energy 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 energy is physically settled, the
purchase price is included as Natural Gas and Petroleum Products Purchases 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.

     Commodity Fair Value Hedges - Changes in the fair value of a derivative
that is designated and qualifies as a fair value hedge, and of the underlying
physical transaction are included in the Consolidated Statements of Income as
Sales of Natural Gas and Petroleum Products and Natural Gas and Petroleum
Products Purchases, as appropriate, with an offsetting amount recorded gross in
the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on
Trading and Hedging Transactions. 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.

     Commodity Cash Flow Hedges - The effective portion of the change in fair
value of the derivative instrument is included in Other Comprehensive Income
(OCI) until earnings are affected by the hedged item. Hedge results are removed
from OCI and recorded in the Consolidated Statements of Income in the same
accounts as the item being

                                       5
<Page>

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, the derivative will continue to be carried on the
balance sheet 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 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. Under these circumstances, gains and losses that were
accumulated in OCI will be recognized in current period earnings.

     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. All components of each derivative gain or loss
are included in the assessment of hedge effectiveness, unless otherwise noted.

     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, income taxes going forward will consist primarily of miscellaneous
state, local and franchise taxes. In addition, the Company has Canadian
subsidiaries that are levied certain foreign 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.

     The Company is required to make quarterly distributions to Duke Energy
Corporation (Duke Energy) and Phillips Petroleum Company (Phillips) based on
allocated taxable income. 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.

     CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE - The Company adopted
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," 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 nine months ended September 30, 2001, the Company reclassified to
earnings $14.4 million of losses from OCI for derivatives included in the
transition adjustment that have settled. The amounts reclassified out of OCI
will be different from the amounts included in the transition adjustment due to
market price changes between January 1, 2001 and when the hedge transactions
settled.

     In June 2001, the FASB cleared Issue C10, "Scope Exceptions: Can Option
Contracts and Forward Contracts with Optionality Features Qualify for the Normal
Purchases and Normal Sales Exception." C10 states that normal purchases and
normal sales exception applies only to contracts that provide for the purchase
or sale of something other than a financial instrument or derivative instrument
that will be delivered in quantities expected to be used or sold over a
reasonable period, in the normal course of business. Therefore, purchased option
contracts (including net purchased options) and written option contracts
(including net written options) that would require delivery of the related asset
at an established price under the contract only if exercised are not eligible to
qualify for the normal purchases and normal sales exception. The Company does
not believe that the adoption of C10 will have a significant impact on its
consolidated results of operations, cash flows or financial position.

     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. 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 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

                                       6
<Page>

life, as previously required. Instead, goodwill amounts will be subject to a
fair-value-based annual impairment assessment as described by the new standard.
SFAS No. 142 also requires acquired intangible assets to be recognized
separately and amortized as appropriate.

     The Company expects that the adoption of SFAS No. 142 will have an impact
on future financial statements due to the discontinuation of goodwill
amortization expense. For the nine months ended September 30, 2001 amortization
expense for goodwill was $22.1 million. The Company is conducting an impairment
assessment at levels defined in the new standard and currently does not have an
estimate of the impact on its consolidated results of operation, cash flows, or
financial position.

     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. SFAS No. 143
is effective for fiscal years beginning after June 15, 2002, and early adoption
is permitted. The Company is currently assessing but has not yet determined the
impact of SFAS No. 143 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, 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 is currently assessing the
new standard and has not yet determined the impact on its consolidated results
of operations, cash flows or financial position.

     RECLASSIFICATIONS - Certain prior period amounts have been reclassified in
the Consolidated Financial Statements to conform to the current presentation.

3.   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 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 such 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.

     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.

     CORPORATE ECONOMIC RISKS - From time to time, the Company will enter into
debt arrangements that are exposed to market risks related to changes in
interest rates. The Company periodically utilizes interest rate lock

                                       7
<Page>

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
averages.

     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 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 nine months ended September 30, 2001, the Company did not recognize
material gains or losses representing the ineffective portion of its fair value
hedges. 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 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 futures,
over-the-counter swap agreements and options to hedge the impact of market
fluctuations in the price of natural gas liquids and other energy-related
products. For the nine months ended September 30, 2001, the Company recognized a
net loss of $6.8 million of which a $2.3 million gain represented the total
ineffectiveness of all cash flow hedges and a $9.1 million loss represented the
total derivative settlements. The time value of the options, a recognized $5.1
million gain for the period ended September 30, 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 September 30, 2001, $16.7 million of
the deferred net gains on derivative instruments accumulated in OCI are expected
to be reclassified as earnings during the next twelve months as the hedge
transactions occur. The maximum term over which the Company is hedging its
exposure to the variability of future cash flows is 24 months.

     INTEREST RATE FAIR VALUE HEDGE - In October 2001, the Company entered an
interest rate swap to hedge the fixed interest rate of $250.0 million of debt
securities that were issued in August 2000. The interest rate fair value hedge
is at a floating rate based on 6-month LIBOR rates.

4.   ACQUISITION

                                       8
<Page>

     On May 1, 2001, the Company acquired the outstanding shares of Canadian
Midstream Services, Ltd. (CMSL) for a total purchase price of approximately
$162.0 million. The purchase price included the assumption of 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. Revenues and net income for the nine months ended
September 30, 2001 on a pro forma basis would have increased $7.8 million and
$1.4 million respectively, if the acquisition of CMSL had occurred on January 1,
2001. The purchase price has not yet been fully allocated to the individual
assets and liabilities acquired. No goodwill has been recorded as a result of
the preliminary allocation.

     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 $40.0 million. The pro forma impact of the acquisition on the
Company's results of operations was not material.

     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
$67.4 million. 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. The pro forma impact of
the acquisition on the Company's results of operations was not material.

5.   FINANCING

     CREDIT FACILITY WITH FINANCIAL INSTITUTIONS - On March 30, 2001, the
Company entered into a new credit facility (the "New Facility"). The New
Facility replaces the credit facility that matured on March 30, 2001. The New
Facility is used to support the Company's commercial paper program and for
working capital and other general corporate purposes. The New Facility matures
on March 29, 2002, however, any outstanding loans under the New Facility at
maturity may, at the Company's option, be converted to a one-year term loan. The
New Facility is a $675.0 million revolving credit facility, of which $150.0
million can be used for letters of credit. The New Facility requires the Company
to maintain at all times a debt to total capitalization ratio of less than or
equal to 53%. The New Facility bears interest at a rate equal to, at the
Company's option and based on the Company's current debt rating, 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 September 30, 2001,
the Company has a $45 million letter of credit issued and outstanding against
the New Facility, and there were no outstanding borrowings against the New
Facility.

     DEBT SECURITIES - On February 2, 2001, the Company issued $250.0 million in
debt securities. The notes mature and become due and payable on February 1,
2011, and are not subject to any sinking fund provisions. The notes bear
interest at 6 7/8%, payable semiannually. The notes are redeemable at the option
of the Company. The Company used the proceeds from the issuance of the notes to
repay short term debt.

     On November 9, 2001, the Company issued $300.0 million of senior unsecured
notes. The notes mature and become due and payable on November 15, 2006, and are
not subject to any sinking fund provisions. The notes bear interest at 5.75%,
payable semiannually. The notes are redeemable at the option of the Company. The
Company used the proceeds from the issuance of the notes to repay short-term
debt.

                                       9
<Page>

6.   COMMITMENTS AND CONTINGENT LIABILITIES

     LITIGATION - 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 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 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. At this time, the
Company is evaluating its alternatives and the impact, if any, this decision
will have on the Company. The Company has signed a non-binding letter of intent
with Williams to settle all issues associated with this matter. The settlement
contemplates the exchange of the Acquired Assets for certain assets of Williams
in the Texas Panhandle and Western Oklahoma areas.

     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 eleven 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 to settle allegations
reflected in a June 2001 notice from the agency relating to the Company's Port
Arthur natural gas processing plant. The Proposed Agreed Order seeks 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 is discussing
settlement terms with the agency.

     The Company has resolved its issues with the Colorado Air Pollution Control
Division, first disclosed in the Company's last Form 10-K, regarding various
asserted non-compliance issues arising from agency inspections of the Company's
Colorado facilities in 2000 and 1999, and arising from compliance issues
disclosed to the agency pursuant to permit requirements or voluntarily disclosed
to the agency in 2000. These items relate to various specific and detailed terms
of the Title V Operating Permits at seven gas plants and two compressor stations
in Colorado, including, for example, record keeping requirements, parametric
monitoring requirements, delayed filings, and operations inconsistent with
throughput limits on particular pieces of equipment. In October 2001, the
Company entered into a Compliance Order and Consent which requires the Company
to pay a penalty of $97,000 and undertake supplemental environmental projects
totaling $388,000.

     In addition to the litigation and environmental matters discussed above,
from time to time, the Company is named as a party in legal and other
proceedings arising in the ordinary course of business. The Company believes it
has meritorious defenses to all of these proceedings and will vigorously defend
against them. Based on the Company's evaluation of pending matters and after
consideration of reserves established, the Company believes that resolution of
these proceedings will not have a material adverse effect on the consolidated
results of operations, cash flows or financial position of the Company.

                                       10
<Page>

7.   BUSINESS SEGMENTS

     The Company operates in two principal business segments as follows: (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 2. Foreign operations
are not material and are therefore not separately identified.


                                       11
<Page>

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

<Table>
<Caption>
                                                               FOR THE THREE                      FOR THE NINE
                                                               MONTHS ENDED                       MONTHS ENDED
                                                               SEPTEMBER 30,                      SEPTEMBER 30,
                                                        ----------------------------      ----------------------------
                                                           2001              2000             2001             2000
                                                        -----------      -----------      -----------      -----------
                                                                                 (IN THOUSANDS)
<S>                                                     <C>              <C>              <C>              <C>
Operating revenues:
   Natural gas ....................................     $ 1,416,038      $ 2,074,644      $ 5,371,286      $ 4,649,651
   NGLs ...........................................         686,154          828,858        3,781,084        2,447,725
   Intersegment(a) ................................        (421,065)        (351,507)      (1,554,846)        (921,810)
                                                        -----------      -----------      -----------      -----------
      Total operating revenues ....................     $ 1,681,127      $ 2,551,995      $ 7,597,524      $ 6,175,566
                                                        ===========      ===========      ===========      ===========
Margin:
   Natural gas ....................................     $   305,107      $   338,670      $   980,214      $   809,751
   NGLs ...........................................          12,760           12,330           41,446           49,783
                                                        -----------      -----------      -----------      -----------
      Total margin ................................     $   317,867      $   351,000      $ 1,021,660      $   859,534
                                                        ===========      ===========      ===========      ===========
Other operating costs:
   Natural gas ....................................     $    94,064      $    92,677      $   270,365      $   232,193
   NGLs ...........................................           2,464              753            4,711            1,928
   Corporate ......................................          34,070           42,245           99,517          112,221
                                                        -----------      -----------      -----------      -----------
      Total other operating costs .................     $   130,598      $   135,675      $   374,593      $   346,342
                                                        ===========      ===========      ===========      ===========
Equity in earnings of unconsolidated affiliates:
   Natural Gas ....................................     $     5,765      $     3,675      $    21,887      $    17,563
   NGLs ...........................................             779              633              737            1,452
                                                        -----------      -----------      -----------      -----------
      Total equity in earnings of unconsolidated
         affiliates ...............................     $     6,544      $     4,308      $    22,624      $    19,015
                                                        ===========      ===========      ===========      ===========
EBITDA(b):
   Natural gas ....................................     $   216,808      $   249,668      $   731,736      $   595,121
   NGLs ...........................................          11,075           12,210           37,472           49,307
   Corporate ......................................         (34,070)         (42,245)         (99,517)        (112,221)
                                                        -----------      -----------      -----------      -----------
      Total EBITDA ................................     $   193,813      $   219,633      $   669,691      $   532,207
                                                        ===========      ===========      ===========      ===========
Depreciation and amortization:
   Natural gas ....................................     $    69,056      $    58,690      $   197,265      $   156,357
   NGLs ...........................................           2,402            3,133            6,780            9,245
   Corporate ......................................           1,139            1,001            3,269            2,581
                                                        -----------      -----------      -----------      -----------
      Total depreciation and amortization .........     $    72,597      $    62,824      $   207,314      $   168,183
                                                        ===========      ===========      ===========      ===========
EBIT(b):
   Natural gas ....................................     $   147,752      $   190,978      $   534,471      $   438,764
   NGLs ...........................................           8,673            9,077           30,692           40,062
   Corporate ......................................         (35,209)         (43,246)        (102,786)        (114,802)
                                                        -----------      -----------      -----------      -----------
      Total EBIT ..................................     $   121,216      $   156,809      $   462,377      $   364,024
                                                        ===========      ===========      ===========      ===========

Corporate interest expense ........................     $    42,455      $    46,343      $   124,847      $   106,194
                                                        ===========      ===========      ===========      ===========
Income before income taxes:
   Natural gas ....................................     $   147,752      $   190,978      $   534,471      $   438,764
   NGLs ...........................................           8,673            9,077           30,692           40,062
   Corporate ......................................         (77,664)         (89,589)        (227,633)        (220,996)
                                                        -----------      -----------      -----------      -----------
      Total income before income taxes ............     $    78,761      $   110,466      $   337,530      $   257,830
                                                        ===========      ===========      ===========      ===========
</Table>


                                       12
<Page>

<Table>
<Caption>
                                                               FOR THE THREE                      FOR THE NINE
                                                               MONTHS ENDED                       MONTHS ENDED
                                                               SEPTEMBER 30,                      SEPTEMBER 30,
                                                        ----------------------------      ----------------------------
                                                           2001              2000             2001             2000
                                                        -----------      -----------      -----------      -----------
                                                                                 (IN THOUSANDS)
<S>                                                     <C>              <C>              <C>              <C>
Acquisitions and other capital expenditures:
   Natural gas ....................................     $   133,991      $    43,509      $   423,844      $   248,697
   NGLs ...........................................              --              657            7,584            6,487
   Corporate ......................................           5,357            5,670           16,615            8,921
                                                        -----------      -----------      -----------      -----------
      Total acquisitions and other
         capital expenditures .....................     $   139,348      $    49,836      $   448,043      $   264,105
                                                        ===========      ===========      ===========      ===========
</Table>

<Table>
<Caption>
                                             AS OF
                                  ---------------------------
                                  SEPTEMBER 30,  DECEMBER 31,
                                      2001           2000
                                  -------------  ------------
                                        (IN THOUSANDS)
<S>                               <C>            <C>
Total assets:
   Natural gas ...............     $5,310,557     $4,896,542
   NGLs ......................        349,785        219,282
   Corporate(c) ..............        928,954      1,054,274
                                   ----------     ----------
           Total assets ......     $6,589,296     $6,170,098
                                   ==========     ==========
</Table>

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

(b)  EBITDA consists of income from continuing operations before interest
     expense, income tax expense, and depreciation and amortization expense.
     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.

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


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

     THE FOLLOWING DISCUSSION DETAILS THE MATERIAL FACTORS THAT AFFECTED OUR
HISTORICAL FINANCIAL CONDITION AND RESULTS OF OPERATIONS DURING THE THREE MONTHS
AND NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000. THIS DISCUSSION SHOULD BE
READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES
INCLUDED ELSEWHERE IN THIS REPORT.

     DUKE ENERGY FIELD SERVICES, LLC HOLDS THE COMBINED NORTH AMERICAN MIDSTREAM
NATURAL GAS GATHERING, PROCESSING, MARKETING AND NATURAL GAS LIQUIDS BUSINESS OF
DUKE ENERGY CORPORATION (DUKE ENERGY) AND PHILLIPS PETROLEUM COMPANY (PHILLIPS).
THE TRANSACTION IN WHICH THOSE BUSINESSES WERE COMBINED ON MARCH 31, 2000 IS
REFERRED TO AS THE "COMBINATION." IN THIS REPORT, 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

                                       13
<Page>

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." THE HISTORICAL FINANCIAL STATEMENTS AND
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 PARTNERS, L.P.(TEPPCO) FROM DUKE
ENERGY.

OVERVIEW

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

     o    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;

     o    natural gas liquids (NGLs) fractionation, transportation, marketing
          and trading, from which we generate revenues from transportation fees,
          market center fractionation and the marketing and trading of NGLs.

     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

     During the nine months ended September 30, 2001, the weighted average NGL
price (based on index prices from the Mont Belvieu and Conway market hubs that
are weighted by our component and location mix) was approximately $.49 per
gallon. Historically, NGL prices have generally followed changes in crude oil
prices. However, during the first quarter of 2001, NGL prices departed from this
trend and followed the sharp increase in natural gas prices. Despite the impact
of the natural gas price spike experienced during the first quarter, we expect
that NGL prices will generally follow changes in crude oil prices, 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. We also believe that should the recent rise in natural gas prices be
sustained, certain NGL component prices will generally remain higher than
historical levels. In contrast, we believe that future natural gas prices will
be influenced by supply deliverability, the severity of winter weather and the
level of U.S. economic growth. We believe that weather will be the strongest
determinant of near-term natural gas prices. Price increases in crude oil, NGLs
and natural gas have continued to spur increased natural gas drilling activity.
For example, the number of active drilling rigs in North America has increased
by approximately 14 % from approximately 1,325 in September 2000 to
approximately 1,510 in September 2001. This drilling activity increase is
expected to have a positive effect on natural gas volumes gathered and processed
in the near term.

                                       14
<Page>

RESULTS OF OPERATIONS

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

THREE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH THREE MONTHS ENDED
SEPTEMBER 30, 2000

     OPERATING REVENUES. Operating revenues decreased $870.9 million, or 34%,
from $2,552.0 million for the third quarter 2000 to $1,681.1 million for the
same period in 2001. Operating revenues from the sale of natural gas and
petroleum products accounted for $1,598.4 million of the total and $902.8
million of the decrease. NGL production during the third quarter decreased 4,200
barrels per day, or 1%, from 417,000 barrels per day in 2000 to 412,800 barrels
per day in 2001.

     Commodity prices were the main factor contributing to lower revenues during
the third quarter. Weighted average NGL prices, based on our component product
mix, were approximately $.16 per gallon lower and natural gas prices were
approximately $1.39 per million British thermal units (Btus) lower for the third
quarter of 2001. These price decreases yielded average prices of $.39 per gallon
and $2.88 per million Btus, respectively, as compared with $.55 per gallon and
$4.27 per million Btus for the third quarter of 2000. Revenues associated with
gathering, transportation, storage, processing fees and other increased $31.9
million, or 63%, from $50.8 million for the third quarter 2000 to $82.7 million
for the same period in 2001. This increase was mainly the result of the December
31, 2000 purchase of the Guadalupe Pipeline System, increased fee based
processing and storage activities and the May 1, 2001 purchase of Canadian
Midstream Services, Ltd. A $14.1 million hedging gain in the third quarter of
2001 partially offset operating revenue decreases. See "--Quantitative and
Qualitative Disclosure About Market Risks."

     COSTS AND EXPENSES. Costs of natural gas and petroleum products decreased
$837.7 million, or 38%, from $2,201.0 million for the third quarter 2000 to
$1,363.3 million for the same period in 2001. This decrease was primarily due to
the interaction of our natural gas and NGL purchase contracts with lower
commodity prices.

     Operating and maintenance expenses increased $4.7 million, or 5%, from
$92.6 million for the third quarter of 2000 to $97.3 million for the same period
in 2001. General and administrative expenses decreased $8.9 million, or 21%,
from $42.2 million for the third quarter of 2000 to $33.3 million for the same
period in 2001. The net overall decrease was primarily the result of cost
reduction efforts, plant consolidation, decreased centralized service charges
from our parents and lower bonus accruals, offset to a degree by increases from
partnerships accounted for under the equity method prior to the acquisition of
additional interests discussed below.

     Depreciation and amortization increased $9.8 million from $62.8 million for
the third quarter of 2000 to $72.6 million for the same period in 2001. This
increase was due to the purchase of additional interests in certain offshore
partnership properties from MCNIC. This purchase resulted in increasing our
respective interests in three partnerships to greater than 50% requiring us to
consolidate 100% of the partnership activity. Other increases are due to the
Guadalupe Pipeline System, Canadian Midstream Services, Ltd, and GSRI
acquisitions, and continued capital expenditures for well connections and
facility maintenance.

     EQUITY IN EARNINGS. Equity in earnings of unconsolidated affiliates
increased $2.2 million, or 51%, from $4.3 million for the third quarter of 2000
to $6.5 million for the same period in 2001. This increase was due primarily to
increased earnings associated with the general partnership interest in TEPPCO,
offset by the consolidation of the partnerships associated with the MCNIC
transaction.

                                       15
<Page>

     INTEREST. Interest expense decreased $3.8 million, or 8%, from $46.3
million for the third quarter 2000 to $42.5 million for the same period in 2001.
This decrease was primarily due to lower average outstanding debt and lower
average interest rates

     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 of $327.0 million was eliminated and a corresponding
income tax benefit was recorded. Ongoing tax expenses relate to various state,
local and foreign taxes that are not significant.

     NET INCOME. Net income decreased $35.5 million from $114.3 million for the
third quarter 2000 to $78.8 million for the same period in 2001. This decrease
was primarily the result of lower commodity prices offset by increased equity
earnings from TEPPCO, cost reduction efforts, and increased fee based services.

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

     EBITDA for the natural gas gathering, processing, transportation and
storage segment decreased $32.9 million from $249.7 million for the third
quarter 2000 to $216.8 million for the same period in 2001. This decrease was
primarily the result of lower earnings resulting from the interaction of our gas
purchase contracts with higher commodity prices. Cost reduction initiatives and
decreased centralized service charges from our parents partially offset this
decrease and contributed $8.1 million to EBITDA during the third quarter of
2001.

     EBITDA for the NGL's fractionation, transportation, marketing and trading
segment decreased $1.1 million from $12.2 million for the third quarter 2000 to
$11.1 million for the same period in 2001 due primarily to lower margins
associated with NGL trading, and the disposition of two NGL pipelines effective
January 1, 2001.

NINE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH NINE MONTHS ENDED
SEPTEMBER 30, 2000

     OPERATING REVENUES. Operating revenues increased $1,421.9 million, or 23%,
from $6,175.6 million for the nine months ended September 30, 2000 to $7,597.5
million for the same period in 2001. Operating revenues from the sale of natural
gas and petroleum products accounted for $7,395.3 million of the total and
$1,364.3 million of the increase. Of this increase, approximately $1,064.1
million was related to the addition of the Phillips' midstream natural gas
business to our operations in the Combination on March 31, 2000. NGL production
during the nine months ended September 30, 2001 increased 47,000 barrels per
day, or 13%, from 349,900 barrels per day in 2000 to 396,900 barrels per day in
2001. The primary cause of this increase was the addition of Phillips' midstream
natural gas business, offset by reduced recoveries at certain facilities
resulting from tightened fractionation spreads driven by high natural gas prices
during the first six months of 2001.

     Higher natural gas prices also contributed to higher revenues. Natural gas
prices were approximately $1.46 per million British thermal units (Btus) higher
for the nine months ended September 30, 2001. Lower weighted average NGL prices,
based on our component product mix, partially offset this increase and were
approximately $.02 per gallon lower for the same period. These price changes
yielded average prices of $.49 per gallon and $4.88 per million Btus,
respectively, as compared with $.51 per gallon and $3.42 per million Btus for
the same period in 2000. Revenues

                                       16
<Page>

associated with gathering, transportation, storage, processing fees and other
increased $57.6 million, or 40%, from $144.6 million for the nine months ended
September 30, 2000 to $202.2 million for the same period in 2001, mainly as a
result of the Combination and increased fee based activities associated with
acquisitions and processing arrangements. A $1.7 million hedging loss during the
nine months ended September 30, 2001 partially offset operating revenue
increases. See "--Quantitative and Qualitative Disclosure About Market Risks."

     COSTS AND EXPENSES. Costs of natural gas and petroleum products increased
$1,259.9 million, or 24%, from $5,316.0 million for the nine months ended
September 30, 2000 to $6,575.9 million for the same period in 2001. This
increase was due to the addition of the Phillips' midstream natural gas business
in the Combination (approximately $881.4) and the interaction of our natural gas
and NGL purchase contracts with higher natural gas prices.

     Operating and maintenance expenses increased $43.8 million, or 19%, from
$233.0 million for the nine months ended September 30, 2000 to $276.8 million
for the same period in 2001. Of this increase, approximately $35.6 million was
related to the addition of the Phillips' midstream natural gas business. General
and administrative expenses decreased $13.5 million, or 12%, from $112.2 million
for the nine months ended September 30, 2000 to $98.7 million for the same
period in 2001. This decrease was primarily the result of cost savings
initiatives and decreased centralized service charges from our parents,
partially offset by increased activity resulting from the addition of the
Phillips' midstream natural gas business in the Combination.

     Depreciation and amortization increased $39.1 million, or 23%, from $168.2
million for the nine months ended September 30, 2000 to $207.3 million for the
same period 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.

     EQUITY IN EARNINGS. Equity in earnings of unconsolidated affiliates
increased $3.6 million, or 19%, from $19.0 million for the nine months ended
September 30, 2000 to $22.6 million for the same period in 2001. This increase
was due to higher earnings from our general partnership interest in TEPPCO,
partially offset by the combination of the divestiture of certain joint venture
(JV) interests in the Conoco/Mitchell transaction, divestiture of the Westana JV
and reduced earnings from consolidating the partnership activity of Mobile Bay
Processing Partners, Gulf Coast NGL Pipeline, L.L.C. and Dauphin Island
Gathering Partners.

     INTEREST. Interest expense increased $18.6 million, or 18%, from $106.2
million for the nine months ended September 30, 2000 to $124.8 million for the
same period in 2001. This increase was primarily the result of issuance of
commercial paper and the subsequent debt offerings.

     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 of $327.0 million was eliminated and a corresponding
income tax benefit was recorded. Ongoing tax expenses relate to various state,
local and foreign taxes that are not significant.

     NET INCOME. Net income decreased $231.5 million from $568.4 million for the
nine months ended September 30, 2000 to $336.9 million for the same period in
2001. This decrease was the result of the elimination of the predecessor
Company's net deferred tax liability of $310.6 million in 2000, offset by a
$79.7 million increase resulting from the addition of the Phillips' midstream
natural gas business in the Combination, cost savings and other acquisitions.

     EBITDA for the natural gas gathering, processing, transportation and
storage segment increased $136.6 million from $595.1 million for the nine months
ended September 30, 2000 to $731.7 million for the same period in 2001. Of this
increase, approximately $152.3 million was due to the addition of the Phillips'
midstream natural gas business in the Combination. Additional increases were
attributable to the Conoco/Mitchell transaction, other acquisitions and the
acquisition of the general partnership interest in TEPPCO as of March 31, 2000.
The increases were offset by approximately $43.8 million due to a $1.46 per
million Btu increase in natural gas prices, approximately $29.2 million due to a
$.02 per gallon decrease in average NGL prices and hedging losses of $1.7
million.

                                       17
<Page>

     EBITDA for the NGL's fractionation, transportation, marketing and trading
segment decreased $11.8 million from $49.3 million for the nine months ended
September 30, 2000 to $37.5 million for the same period in 2001 due primarily to
lower first quarter margins associated with NGL trading, and the disposition of
two NGL pipelines effective January 1, 2001.

LIQUIDITY AND CAPITAL RESOURCES

     CREDIT FACILITY WITH FINANCIAL INSTITUTIONS

     On March 30, 2001, we entered into a new credit facility (the "New
Facility"). The New Facility replaces the credit facility that matured on March
30, 2001. The New Facility is used to support the Company's commercial paper
program and for working capital and other general corporate purposes. The New
Facility matures on March 29, 2002, however, any outstanding loans under the New
Facility at maturity may, at the Company's option, be converted to a one-year
term loan. The New Facility is a $675.0 million revolving credit facility, of
which $150.0 million can be used for letters of credit. The New Facility
requires the Company to maintain at all times a debt to total capitalization
ratio of less than or equal to 53%. The New Facility bears interest at a rate
equal to, at the Company's option and based on the Company's current debt
rating, 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
September 30, 2001, there were no borrowings against the New Facility.

     On February 2, 2001, the Company issued $250.0 million in debt securities.
The notes mature and become due and payable on February 1, 2011, and are not
subject to any sinking fund provisions. The notes bear interest at 6 7/8%,
payable semiannually. The notes are redeemable at the option of the Company. The
Company used the proceeds from the issuance of the notes to repay short term
debt.

     On November 9, 2001, the Company issued $300.0 million of senior unsecured
notes. The notes mature and become due and payable on November 15, 2006, and are
not subject to any sinking fund provisions. The notes bear interest at 5.75%,
payable semiannually. The notes are redeemable at the option of the Company. The
Company used the proceeds from the issuance of the notes to repay short-term
debt.

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

     CAPITAL EXPENDITURES

     Our capital expenditures consist of expenditures for acquisitions and
construction of additional gathering systems, processing plants, fractionators
and other facilities and infrastructure in addition to well connections and
refurbishment of our existing facilities. For the nine months ended September
30, 2001, we spent approximately $448 million on capital expenditures. 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
$40.0 million. On May 1, 2001, the Company acquired the outstanding shares of
Canadian Midstream Services, Ltd. (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 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 for approximately $67.4 million.

     Our level of capital expenditures for acquisitions and construction depends
on many factors, including industry conditions, the availability of attractive
acquisition candidates and construction projects, the level of commodity prices

                                       18
<Page>

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.

     CASH FLOWS

     Net cash provided by operating activities for the nine months ended
September 30, 2001 decreased to $336.4 million, from net cash from operating
activities of $611.9 million for the same period in 2000, primarily due to lower
earnings as a result of commodity prices, and funding working capital
requirements with increases in short-term debt. Net cash used in investing
activities was $396.6 million for the nine months ended September 30, 2001
compared to $241.6 million for the same period in 2000. The acquisition of
Canadian Midstream Services, Ltd. and ongoing system development and maintenance
in 2001 were the primary uses of the invested cash. The net cash used in
investing activities was financed through operating activities and proceeds from
the issuance of short term debt. Net cash flows provided by financing activities
was $62.6 million for the nine months ended September 30, 2001 compared to net
cash used in financing activities of $369.4 million for the same period in 2000.
Tax related distributions to parents and repayment of the Company's short term
debt were the primary uses of this cash, offset by issuance of $250.0 million of
6 7/8% Senior Unsecured Notes due 2011 in February 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. 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 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 as described by the new standard.
SFAS No. 142 also requires acquired intangible assets to be recognized
separately and amortized as appropriate.

     We expect that the adoption of SFAS No. 142 will have an impact on future
financial statements due to the discontinuation of goodwill amortization
expense. For the nine months ended September 30, 2001 amortization expense for
goodwill was $22.1 million. We are conducting an impairment assessment at levels
defined by the new standard and currently do not have an estimate of the impact
on our consolidated results of operation, cash flows, or financial position.

     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. SFAS No. 143
is effective for fiscal years beginning after June 15, 2002, and early adoption
is permitted. The Company is currently assessing but has not yet determined the
impact of SFAS No. 143 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, 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 is currently assessing the
new standard and has not yet determined the impact on its consolidated results
of operations, cash flows or financial position.

                                       19
<Page>

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

     We are exposed to market risks associated with interest rates, commodity
prices, and equity prices. Management has established comprehensive risk
management policies to monitor and manage these market risks. The Company's Risk
Management Committee is responsible for the overall approval of market risk
management policies and the delegation of approval and authorization levels. The
Risk Management Committee is comprised of management personnel who receive
periodic updates from standing personnel in the Company's marketing and trading
operations, corporate hedging operations, mid-office function, and back office
control group on commodity price risks and energy marketing and trading
operations. The Company's treasury department manages the Company's credit
risks. There have been no material changes in the Company's market risk since
December 31, 2000.

     COMMODITY PRICE RISK

     We are subject to significant risks due to fluctuations in commodity
prices, primarily with respect to the prices of NGLs that we own as a result of
our processing activities. Based upon the 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 $4.0 million, respectively. After considering the effects of commodity hedge
positions in place at September 30, 2001, it is estimated that if NGL prices
average $.01 per gallon less in the next twelve months pre-tax net income would
decrease $20.0 million. Conversely, it is estimated that if NGL prices average
$.01 per gallon more in the next twelve months pre-tax net income would increase
$20.0 million.

     INTEREST RATE RISK

     As of September 30, 2001, we had approximately $447.1 million outstanding
under a commercial paper program and no outstanding bank borrowings. As a
result, we are exposed to market risks related to changes in interest rates. We
manage our interest rate exposure using a mix of fixed and floating interest
rate debt by entering into interest-rate swaps. In October 2001, we entered into
an interest-rate swap to hedge the fixed interest rate of $250.0 million of debt
securities. The interest rate fair value hedge is at a floating rate based on
6-month LIBOR rates. An increase of .5% in interest rates would result in an
increase in annual interest expense of approximately $2.2 million.

     FOREIGN CURRENCY RISK

     Our primary foreign currency exchange rate exposure at September 30, 2001
was the Canadian dollar. Foreign currency risk associated with this exposure was
not material.



                                       20
<Page>

                           PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     For information concerning litigation and other contingencies, see Part I.
Item 1, Note 6 to the Consolidated Financial Statements, "Commitments and
Contingent Liabilities," of this report and Item 3, "Legal Proceedings,"
included in our Form 10-K for December 31, 2000, which are incorporated herein
by reference.

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits

     None.

(b)  Reports on Form 8-K

     None.



                                       21
<Page>

                                   SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.


                                     DUKE ENERGY FIELD SERVICES, LLC

November 13, 2001                    /s/ John E. Jackson
                                     -------------------------------------
                                     John E. Jackson
                                     Vice President and Chief Financial Officer
                                     (On Behalf of the Registrant and as
                                     Principal Financial and Accounting Officer)





                                       22