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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 JUNE 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 (IRS Employer
of incorporation) 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 [ ]

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

INDEX

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

PART I. FINANCIAL INFORMATION (UNAUDITED)

1. Financial Statements................................................................................... 1
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2001 and 2000.......... 1
Consolidated Statements of Comprehensive Income for the Three and Six Months
Ended June 30, 2001 and 2000..................................................................... 2
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2001 and 2000................ 3
Consolidated Balance Sheets as of June 30, 2001 and December 31, 2000................................ 4
Condensed Notes to Consolidated Financial Statements................................................. 5
2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 12
3. Quantitative and Qualitative Disclosure about Market Risks............................................. 18

PART II. OTHER INFORMATION

1. Legal Proceedings...................................................................................... 20
6. Exhibits and Reports on Form 8-K....................................................................... 20
Signatures............................................................................................. 21
</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 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;

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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.

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, SIX MONTHS ENDED,
JUNE 30, JUNE 30,
---------------------------- ----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------

OPERATING REVENUES:
Sales of natural gas and petroleum products .................. $ 1,892,236 $ 1,766,745 $ 4,274,119 $ 3,017,843
Sales of natural gas and petroleum products--affiliates ...... 582,455 360,613 1,522,754 524,980
Transportation, storage and processing ....................... 61,634 44,397 119,524 79,470
Transportation, storage and processing--affiliates ........... -- 605 -- 1,278
------------ ------------ ------------ ------------
Total operating revenues ............................... 2,536,325 2,172,360 5,916,397 3,623,571
------------ ------------ ------------ ------------
COSTS AND EXPENSES:
Natural gas and petroleum products ........................... 1,994,972 1,743,096 4,694,208 2,995,865
Natural gas and petroleum products--affiliates ............... 205,133 93,430 518,396 119,172
Operating and maintenance .................................... 90,045 91,315 179,536 140,354
Depreciation and amortization ................................ 67,861 67,265 134,717 105,359
General and administrative ................................... 30,368 32,709 58,585 50,143
General and administrative--affiliates ....................... 2,673 7,566 6,862 19,833
Net (gain) loss on sale of assets ............................ (120) 98 (988) 337
------------ ------------ ------------ ------------
Total costs and expenses ............................... 2,390,932 2,035,479 5,591,316 3,431,063
------------ ------------ ------------ ------------
OPERATING INCOME ................................................ 145,393 136,881 325,081 192,508
EQUITY IN EARNINGS OF
UNCONSOLIDATED AFFILIATES .................................... 10,904 7,948 16,080 14,707
INTEREST EXPENSE:
Interest expense ............................................. 40,375 45,374 82,392 45,366
Interest expense--affiliates ................................. -- -- -- 14,485
------------ ------------ ------------ ------------
Total interest expense ................................. 40,375 45,374 82,392 59,851
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE ....................... 115,922 99,455 258,769 147,364
INCOME TAX EXPENSE (BENEFIT) .................................... 280 7,226 338 (306,765)
------------ ------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE ............................................ 115,642 92,229 258,431 454,129
CUMULATIVE EFFECT OF ACCOUNTING
CHANGE, NET OF TAX ........................................... -- -- 411 --
------------ ------------ ------------ ------------
NET INCOME ...................................................... 115,642 92,229 258,020 454,129
DIVIDENDS ON PREFERRED MEMBERS' INTEREST ........................ 7,125 -- 14,250 --
------------ ------------ ------------ ------------
EARNINGS AVAILABLE FOR MEMBERS' INTEREST ........................ $ 108,517 $ 92,229 $ 243,770 $ 454,129
============ ============ ============ ============
</Table>

See Notes to Consolidated Financial Statements.

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5

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
(IN THOUSANDS)

<Table>
<Caption>
THREE MONTHS ENDED, SIX MONTHS ENDED,
JUNE 30, JUNE 30,
------------------------ ------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------

NET INCOME ...................................................... $ 115,642 $ 92,229 $ 258,020 $ 454,129

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Cumulative effect of change in accounting principle .......... -- -- 6,626 --
Foreign currency translation adjustment ...................... 3,059 (284) 2,147 (1,405)
Net unrealized gains (losses) on cash flow hedges ............ 6,866 -- (11,336) --
Reclassification adjustment .................................. (2,053) -- 14,941 --
---------- ---------- ---------- ----------
Total other comprehensive income (loss), net of tax ..... 7,872 (284) 12,378 (1,405)
---------- ---------- ---------- ----------

TOTAL COMPREHENSIVE INCOME ...................................... $ 123,514 $ 91,945 $ 270,398 $ 452,724
========== ========== ========== ==========
</Table>

See Notes to Consolidated Financial Statements.

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

<Table>
<Caption>
SIX MONTHS ENDED,
JUNE 30,
----------------------------
2001 2000
------------ ------------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................................... $ 258,020 $ 454,129
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization .............................................. 134,717 105,359
Deferred income taxes ...................................................... (338) (308,230)
Change in derivative fair value ............................................ 8,128 --
Equity in earnings of unconsolidated affiliates ............................ (16,080) (14,707)
Loss (gain) on sale of assets .............................................. (988) 337
Change in operating assets and liabilities (net of effects of acquisitions)
which provided (used) cash:
Accounts receivable ........................................................ 615 (142,339)
Accounts receivable--affiliates ............................................ 163,184 (93,679)
Inventories ................................................................ 15,274 (39,532)
Unrealized gains on mark-to-market transactions ............................ (62,742) (56,631)
Other current assets ....................................................... 2,879 43,583
Other noncurrent assets .................................................... (11,974) (2,232)
Accounts payable ........................................................... (53,227) 343,541
Accounts payable--affiliates ............................................... (28,537) 6,053
Accrued interest payable ................................................... 5,726 318
Unrealized losses on mark-to-market transactions ........................... 29,522 50,461
Other current liabilities .................................................. (20,072) (7,473)
Other long term liabilities ................................................ (4,659) (14,215)
------------ ------------
Net cash provided by operating activities ............................... 419,448 324,743
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions and other capital expenditures ................................... (308,695) (214,269)
Investment expenditures ....................................................... (1,114) (1,327)
Investment distributions ...................................................... 28,538 12,093
Proceeds from sales of assets ................................................. 18,852 14,220
------------ ------------
Net cash used in investing activities ................................... (262,419) (189,283)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net change in advances--parents ............................................... (2,182) 25,370
Distributions to parents ...................................................... (129,687) (2,744,319)
Proceeds from issuing debt .................................................... 248,358 --
Payment of debt ............................................................... (47,556) (205,610)
Short term debt--net .......................................................... (226,428) 2,790,900
------------ ------------
Net cash used in financing activities ................................... (157,495) (133,659)
------------ ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS .......................................... (466) 1,801
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ................................... 1,553 792
------------ ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD ......................................... $ 1,087 $ 2,593
============ ============

SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION - Cash paid for interest (net of amounts capitalized) ............. $ 30,878 $ 44,180
</Table>

See Notes to Consolidated Financial Statements.

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

<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
------------ ------------

ASSETS
CURRENT ASSETS:
Cash and cash equivalents ..................................................... $ 1,087 $ 1,553
Accounts receivable:
Customers, net ............................................................. 728,618 725,379
Affiliates ................................................................. 90,093 253,277
Other ...................................................................... 87,804 67,316
Inventories ................................................................... 73,630 83,325
Unrealized gains on trading and hedging transactions .......................... 117,039 46,185
Other ......................................................................... 7,969 14,275
------------ ------------
Total current assets .................................................... 1,106,240 1,191,310
------------ ------------
PROPERTY, PLANT AND EQUIPMENT, NET ............................................... 4,419,660 4,152,480
INVESTMENT IN AFFILIATES ......................................................... 249,406 261,551
INTANGIBLE ASSETS:
Natural gas liquids sales contracts, net ...................................... 93,483 97,956
Goodwill, net ................................................................. 365,561 376,195
------------ ------------
Total intangible assets ................................................. 459,044 474,151
------------ ------------
UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS ............................. 11,935 --
OTHER NONCURRENT ASSETS .......................................................... 87,423 90,606
------------ ------------
TOTAL ASSETS ............................................................ $ 6,333,708 $ 6,170,098
============ ============

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade ...................................................................... $ 865,980 $ 915,130
Affiliates ................................................................. 32,927 61,464
Other ...................................................................... 65,872 41,322
Short term debt ............................................................... 119,891 346,410
Unrealized losses on trading and hedging transactions ......................... 88,096 51,179
Accrued interest payable ...................................................... 55,336 49,641
Accrued taxes other than income ............................................... 18,067 21,717
Distributions payable to members .............................................. 23,334 127,561
Other ......................................................................... 100,907 114,408
------------ ------------
Total current liabilities ............................................... 1,370,410 1,728,832
------------ ------------
DEFERRED INCOME TAXES ............................................................ 26,208 --
LONG TERM DEBT ................................................................... 1,941,092 1,688,157
UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS ............................ 10,549 --
OTHER LONG TERM LIABILITIES ...................................................... 33,927 32,274
PREFERRED MEMBERS' INTEREST ...................................................... 300,000 300,000
COMMITMENTS AND CONTINGENT LIABILITIES (Note 6)
MEMBERS' EQUITY:
Members' interest ............................................................. 1,691,730 1,709,290
Retained earnings ............................................................. 949,843 713,974
Accumulated other comprehensive income (loss) ................................. 9,949 (2,429)
------------ ------------
Total members' equity ................................................... 2,651,522 2,420,835
------------ ------------
TOTAL LIABILITIES AND MEMBERS' EQUITY ............................................ $ 6,333,708 $ 6,170,098
============ ============
</Table>

See Notes to Consolidated Financial Statements.

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

1. GENERAL

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

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 recognized in the Consolidated Balance Sheets at their fair
value as Unrealized Gains or Losses on Trading and Hedging Transactions, as
appropriate. On the date the swap, futures or option contracts are entered into,
the Company designates the derivative as held for trading (trading instruments),
a hedge of the fair value of a recognized asset or liability or of an
unrecognized firm commitment (fair value hedges), or a hedge of a forecasted
transaction or future cash flows (cash flow hedges).

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 extrinsic 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 gross in the Consolidated Balance
Sheets as Unrealized Gains or 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 loss on the balance sheet is reclassified to a receivable
or payable account.

Fair Value Hedges - Changes in the fair value of a derivative that is
designated and qualifies as a fair value hedge and 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 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 Statement 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.

Cash Flow Hedges - The fair value of a derivative that is designated
and qualifies as a cash flow hedge is included in the Consolidated Balance
Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions. 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 hedged. The Company
discontinues hedge

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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 effected 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
immediately in earnings.

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 six months ended June 30, 2001, the Company reclassified to earnings a
$16.4 million loss from OCI for derivatives included in the transition
adjustment for hedge transactions that occurred. The amount reclassified out of
OCI will be different from the amount included in the transition adjustment due
to market price changes since January 1, 2001.

Currently, there are ongoing discussions surrounding the implementation
and interpretation of SFAS No. 133 by the Financial Accounting Standards Board's
(FASB) Derivative Implementation Group (DIG). If the definition of derivative
instruments is altered, this may result in another transition adjustment and
impact subsequent operating results.

In June, 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 is
currently evaluating contracts and agreements with embedded optionality
features. Those contracts that include options affecting price are eligible for
the scope exception, but contracts that include options affecting volume are
not.

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.

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.

New Accounting Standards -In June 2001, the Financial Accounting
Standards Board 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.

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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.

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 six months ended June 30, 2001 amortization
expense for goodwill was $6.9 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 Board unanimously approved the issuance of FASB
Statement No. 143 (FAS No. 143), Accounting for Obligations Associated with the
Retirement of Long-Lived Assets. FAS No. 143 provides the accounting
requirements for retirement obligations associated with tangible long-lived
assets. FAS 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 FAS No. 143 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 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

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attractive interest rates based on historical averages. For the six months ended
June 30, 2001, the Company's existing interest rate derivative instruments were
not material to its results of operations, cash flows or financial position.

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.

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 six months ended June 30, 2001, the Company's fair-value hedges
were effective. As such, the Company did not recognize a gain or loss
representing the ineffective portion of all 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 a gain or loss.

Cash-flow hedges - The Company uses cash flow hedging, 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 six months ended June 30, 2001, the Company recognized a net
loss of $14.8 million of which a $0.1 million gain represented the total
ineffectiveness of all cash-flow hedges and a $14.9 million loss represented the
total derivative settlements. The extrinsic value of the options, $1.6 million
for the period ended June 30, 2001, was excluded in the assessment of hedge
effectiveness. 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 June 30, 2001, $9.4 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.

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4. ACQUISITION

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 $47.6 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 six months ended
June 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 proforma 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 June 30, 2001, there
were no 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.

6. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation - A judgment has been entered in the case of Chevron U.S.A.,
Inc. vs. GPM Gas Corporation, a wholly owned subsidiary of Field Services LLC,
upholding and construing most favored nations clauses in three 1961 West Texas
gas purchase contracts. The U.S. District Court for the Western District of
Texas, Midland Division decided in September 1999 that GPM owes Chevron damages,
interest and attorney's fees under these contracts. GPM appealed the judgment to
the U.S. Court of Appeals for the Fifth Circuit, and on June 1, 2001, the Fifth
Circuit affirmed the judgment against GPM. The judgment, including interest,
attorney's fees and costs, totaled approximately $16.5 million as of the date of
the Fifth Circuit's ruling. On June 15, 2001, GPM filed petitions for rehearing
and rehearing en banc with the Fifth Circuit which were denied on July 6, 2001.
The Company had previously provided an adequate reserve for this case.

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

9
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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 on 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.

Environmental - The Company has resolved non-compliance issues with the
Texas Natural Resources Conservation Commission associated with the timing of
air permit annual compliance certifications submitted to the agency in 1999 and
1998. This matter, a large portion of which was voluntarily self-disclosed to
the agency, involves approximately 120 of the Company's facilities that did not
meet specific administrative filing deadlines for required air permit paperwork.
In addition, the Company resolved with the New Mexico Environment Department
alleged non-compliance with various air permit requirements at four of the
Company's New Mexico facilities. These matters, the majority of which were also
voluntarily self-disclosed to the agency, generally involve document preparation
and submittal as required by permits, compliance testing requirements at two
facilities, and compliance with permit emissions limits at one facility. These
issues with the Texas and New Mexico agencies under relevant air programs
resulted in total penalty settlements of approximately $470,000.

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 will continue to negotiate with NMED to resolve all issues relating to
the alleged violations.

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

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.

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

<Table>
<Caption>
FOR THE THREE FOR THE SIX
MONTHS ENDED MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- ----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
(IN THOUSANDS)

Operating revenues:
Natural gas ................................................... $ 1,211,835 $ 1,675,793 $ 3,955,248 $ 2,575,007
NGLs .......................................................... 1,867,100 820,051 3,094,930 1,618,867
Intersegment(a) ............................................... (542,610) (323,484) (1,133,781) (570,303)
------------ ------------ ------------ ------------
Total operating revenues ................................ $ 2,536,325 $ 2,172,360 $ 5,916,397 $ 3,623,571
============ ============ ============ ============
Margin:
Natural gas ................................................... $ 319,350 $ 323,225 $ 675,107 $ 471,081
NGLs .......................................................... 16,870 12,609 28,686 37,453
------------ ------------ ------------ ------------
Total margin ............................................ $ 336,220 $ 335,834 $ 703,793 $ 508,534
============ ============ ============ ============
Other operating costs:
Natural gas ................................................... $ 88,064 $ 90,787 $ 176,301 $ 139,516
NGLs .......................................................... 1,861 626 2,247 1,175
Corporate ..................................................... 33,041 40,275 65,447 69,976
------------ ------------ ------------ ------------
Total other operating costs ............................. $ 122,966 $ 131,688 $ 243,995 $ 210,667
============ ============ ============ ============
Equity in earnings of unconsolidated affiliates:
Natural Gas ................................................... $ 10,458 $ 7,374 $ 16,122 $ 13,888
NGLs .......................................................... 446 574 (42) 819
------------ ------------ ------------ ------------
Total equity in earnings of unconsolidated affiliates ... $ 10,904 $ 7,948 $ 16,080 $ 14,707
============ ============ ============ ============
EBITDA(b):
Natural gas ................................................... $ 241,744 $ 239,812 $ 514,928 $ 345,453
NGLs .......................................................... 15,455 12,557 26,397 37,097
Corporate ..................................................... (33,041) (40,275) (65,447) (69,976)
------------ ------------ ------------ ------------
Total EBITDA ............................................ $ 224,158 $ 212,094 $ 475,878 $ 312,574
============ ============ ============ ============
Depreciation and amortization:
Natural gas ................................................... $ 64,728 $ 63,442 $ 128,209 $ 97,667
NGLs .......................................................... 2,083 3,085 4,378 6,112
Corporate ..................................................... 1,050 738 2,130 1,580
------------ ------------ ------------ ------------
Total depreciation and amortization ..................... $ 67,861 $ 67,265 $ 134,717 $ 105,359
============ ============ ============ ============
EBIT(b):
Natural gas ................................................... $ 177,016 $ 176,370 $ 386,719 $ 247,786
NGLs .......................................................... 13,372 9,472 22,019 30,985
Corporate ..................................................... (34,091) (41,013) (67,577) (71,556)
------------ ------------ ------------ ------------
Total EBIT .............................................. $ 156,297 $ 144,829 $ 341,161 $ 207,215
============ ============ ============ ============
Corporate interest expense ....................................... $ 40,375 $ 45,374 $ 82,392 $ 59,851
============ ============ ============ ============
Income before income taxes:
Natural gas ................................................... $ 177,016 $ 176,370 $ 386,719 $ 247,786
NGLs .......................................................... 13,372 9,472 22,019 30,985
Corporate ..................................................... (74,466) (86,387) (149,969) (131,407)
------------ ------------ ------------ ------------
Total income before income taxes ........................ $ 115,922 $ 99,455 $ 258,769 $ 147,364
============ ============ ============ ============
</Table>

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15

<Table>
<Caption>
FOR THE THREE FOR THE SIX
MONTHS ENDED MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
(IN THOUSANDS)

Acquisitions and other capital expenditures:
Natural gas .................................................. $ 195,371 $ 83,393 $ 256,256 $ 205,188
NGLs ......................................................... 40,641 68 41,181 5,830
Corporate .................................................... 9,565 1,217 11,258 3,251
---------- ---------- ---------- ----------
Total acquisitions and other capital expenditures ...... $ 245,577 $ 84,678 $ 308,695 $ 214,269
========== ========== ========== ==========
</Table>

<Table>
<Caption>
AS OF
-----------------------------------
JUNE 30, DECEMBER 31,
2001 2000
---------------- ---------------
(IN THOUSANDS)

Total assets:
Natural gas............................................................. $ 5,092,810 $ 4,896,542
NGLs .................................................................. 206,854 219,282
Corporate(c)............................................................ 1,034,044 1,054,274
---------------- ---------------
Total assets...................................................... $ 6,333,708 $ 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.

8. SUBSEQUENT EVENTS

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. As a result of this
acquisition, the Company will consolidate these affiliates due to the Company's
control.

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 six months ended June 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.

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16

From a financial reporting perspective, we are the successor to Duke
Energy's North American midstream natural gas business. The subsidiaries of Duke
Energy that conducted this business were contributed to us immediately prior to
the Combination. For periods prior to the Combination, Duke Energy Field
Services and these subsidiaries of Duke Energy are collectively referred to
herein as the "Predecessor Company." 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 six months ended June 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 $0.54 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 35% from approximately 1,169 in June 2000 to approximately
1,573 in June 2001. This drilling activity increase is expected to have a
positive effect on natural gas volumes gathered and processed in the near term.

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17

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

Operating Revenues. Operating revenues increased $363.9 million, or
17%, from $2,172.4 million for the second quarter 2000 to $2,536.3 million for
the same period in 2001. Operating revenues from the sale of natural gas and
petroleum products accounted for $2,474.7 million of the total and $347.3
million of the increase. NGL production during the second quarter increased
5,200 barrels per day, or 1%, from 401,500 barrels per day in 2000 to 406,700
barrels per day in 2001.

Commodity prices were the main factor contributing to higher revenues
during the second quarter. Weighted average NGL prices, based on our component
product mix, were approximately $.01 per gallon higher and natural gas prices
were approximately $1.20 per million British thermal units (Btus) higher for the
second quarter of 2001. These price increases yielded average prices of $.48 per
gallon and $4.67 per million Btus, respectively, as compared with $.47 per
gallon and $3.47 per million Btus for the second quarter of 2000. Revenues
associated with gathering, transportation, storage, processing fees and other
increased $16.6 million, or 37%, from $45.0 million for the second quarter 2000
to $61.6 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 $1.2 million hedging loss in the
second quarter of 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 $363.6 million, or 20%, from $1,836.5 million for the second quarter
2000 to $2,200.1 million for the same period in 2001. This increase was
primarily due to the interaction of our natural gas and NGL purchase contracts
with higher natural gas prices.

Operating and maintenance expenses decreased $1.3 million, or 1%, from
$91.3 million for the second quarter of 2000 to $90.0 million for the same
period in 2001. General and administrative expenses decreased $7.3 million, or
18%, from $40.3 million for the second quarter of 2000 to $33.0 million for the
same period in 2001. These decreases were primarily the result of cost reduction
efforts, plant consolidation and decreased centralized service charges from our
parents.

Depreciation and amortization increased $0.6 million from $67.3 million
for the second quarter of 2000 to $67.9 million for the same period in 2001.
This slight increase was due to ongoing capital expenditures for well
connections, facility maintenance/enhancements and acquisitions.

Equity Earnings. Equity earnings of unconsolidated affiliates increased
$3.0 million, or 38%, from $7.9 million for the second quarter of 2000 to $10.9
million for the same period in 2001. This increase was due primarily to
increased earnings associated with the general partnership interest in TEPPCO.

Interest. Interest expense decreased $5.0 million, or 11%, from $45.4
million for the second quarter 2000 to $40.4 million for the same period in
2001. This decrease was primarily the result of issuance of commercial paper and
the subsequent third quarter 2000 and first quarter 2001 debt offerings.

14
18

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 increased $23.4 million from $92.2 million for
the second quarter 2000 to $115.6 million for the same period in 2001. This
increase was primarily the result of 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 increased $1.9 million from $239.8 million for the second
quarter 2000 to $241.7 million for the same period in 2001. This increase was
primarily the result of higher earnings for the general partnership interest in
TEPPCO, partially offset by the interaction of our gas purchase contracts with
higher natural gas prices. Cost reduction initiatives and decreased centralized
service charges from our parents contributed $7.3 million to EBITDA during the
second quarter of 2001.

EBITDA for the NGL's fractionation, transportation, marketing and
trading segment increased $2.9 million from $12.6 million for the second quarter
2000 to $15.5 million for the same period in 2001 due primarily to higher
margins associated with NGL trading, partially offset by the disposition of two
NGL pipelines effective January 1, 2001.

SIX MONTHS ENDED JUNE 30, 2001 COMPARED WITH SIX MONTHS ENDED JUNE 30, 2000

Operating Revenues. Operating revenues increased $2,292.8 million, or
63%, from $3,623.6 million for the six months ended June 30, 2000 to $5,916.4
million for the same period in 2001. Operating revenues from the sale of natural
gas and petroleum products accounted for $5,796.9 million of the total and
$2,254.1 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 six months ended June 30, 2001 increased 72,600 barrels per day, or
23%, from 316,300 barrels per day in 2000 to 388,900 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.

Commodity prices also contributed to higher revenues. Weighted average
NGL prices, based on our component product mix, were approximately $.05 per
gallon higher and natural gas prices were approximately $2.89 per million
British thermal units (Btus) higher for the six months ended June 30, 2001.
These price increases yielded average prices of $.54 per gallon and $5.88 per
million Btus, respectively, as compared with $.49 per gallon and $2.99 per
million Btus for the same period in 2000. Revenues associated with gathering,
transportation, storage, processing fees and other increased $38.8 million, or
48%, from $80.7 million for the six months ended June 30, 2000 to $119.5 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
$15.8 million hedging loss during the six months ended June 30, 2001 partially
offset operating revenue increases. See "--Quantitative and Qualitative
Disclosure About Market Risks."

15
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Costs and Expenses. Costs of natural gas and petroleum products
increased $2,097.6 million, or 67%, from $3,115.0 million for the six months
ended June 30, 2000 to $5,212.6 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 commodity prices.

Operating and maintenance expenses increased $39.1 million, or 28%,
from $140.4 million for the six months ended June 30, 2000 to $179.5 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 $4.6 million, or 7%, from $70.0 million
for the six months ended June 30, 2000 to $65.4 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 $29.3 million, or 28%, from
$105.4 million for the six months ended June 30, 2000 to $134.7 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 ongoing capital expenditures for well connections, facility
maintenance/enhancements and acquisitions.

Equity Earnings. Equity earnings of unconsolidated affiliates increased
$1.4 million, or 10%, from $14.7 million for the six months ended June 30, 2000
to $16.1 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 keep whole supply contracts in South Texas and offshore processing
partnerships.

Interest. Interest expense increased $22.5 million, or 38%, from $59.9
million for the six months ended June 30, 2000 to $82.4 million for the same
period in 2001. This increase was primarily the result of issuance of commercial
paper and the subsequent third quarter 2000 and first quarter 2001 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 $196.1 million from $454.1 million for
the six months ended June 30, 2000 to $258.0 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 $327.0 million in 2000, offset by a
$107.5 million increase resulting from the addition of the Phillips' midstream
natural gas business in the Combination, increased commodity prices, cost
savings and other acquisitions.

EBITDA for the natural gas gathering, processing, transportation and
storage segment increased $169.4 million from $345.5 million for the six months
ended June 30, 2000 to $514.9 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, and approximately $65.0
million was due to a $.05 per gallon increase in average NGL prices. Additional
increases were attributable to the Conoco/Mitchell transaction and the
acquisition of the general partnership interest in TEPPCO as of March 31, 2000.
These benefits were offset by approximately $44.9 million due to a $2.99 per
million Btu increase in natural gas prices, and hedging losses of $15.8 million.

EBITDA for the NGL's fractionation, transportation, marketing and
trading segment decreased $10.7 million from $37.1 million for the six months
ended June 30, 2000 to $26.4 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.

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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
June 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.

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 six months ended June 30,
2001, we spent approximately $308.7 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 $47.6 million.

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

CASH FLOWS

Net cash from operating activities for the six months ended June 30,
2001 improved to $419.4 million, from net cash from operating activities of
$324.7 million for the same period in 2000, primarily due to higher commodity
prices and acquisitions. Net cash used in investing activities was $262.4
million for the six months ended June 30, 2001 compared to $189.3 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 used in financing activities was $157.5 million for the six months
ended June 30, 2001 compared to $133.7 million for the same period in 2000. Tax
related distributions to parents and repayment of the Company's short term debt
were

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the primary uses of this cash, offset by issuance of $250 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."

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 six months ended June 30, 2001 amortization expense for
goodwill was $6.9 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 Board unanimously approved the issuance of FASB
Statement No. 143 (FAS No. 143), Accounting for Obligations Associated with the
Retirement of Long-Lived Assets. FAS No. 143 provides the accounting
requirements for retirement obligations associated with tangible long-lived
assets. FAS No. 143 is effective for fiscal years beginning after June 15, 2002,
and early adoption is permitted. We are currently assessing but have not yet
determined the impact of FAS No. 143 on our consolidated results of operations,
cash flows, or financial position.

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.

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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 $(26.0) million
and $3.0 million, respectively. After considering the effects of commodity hedge
positions in place at June 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
$18.7 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 $18.7
million.

INTEREST RATE RISK

As of June 30, 2001, we had approximately $119.9 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. In
the future, we intend to manage our interest rate exposure using a mix of fixed
and floating interest rate debt. An increase of .5% in interest rates would
result in an increase in annual interest expense of approximately $0.6 million.

FOREIGN CURRENCY RISK

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

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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

10.1 364-Day Credit Facility among Duke Energy Field Services, LLC,
Duke Energy Field Services Corporation, Bank of America, N.A.,
as Agent and the Lenders named therein, dated March 30, 2001

(b) Reports on Form 8-K

None.

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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

August 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)

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EXHIBIT INDEX

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

10.1 364-Day Credit Facility among Duke Energy Field Services, LLC,
Duke Energy Field Services Corporation, Bank of America, N.A.,
as Agent and the Lenders named therein, dated March 30, 2001
</Table>