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

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____________________
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934

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

For Quarter Ended March 31, 2002 Commission File Number 0-31095
DUKE ENERGY FIELD SERVICES, LLC
(Exact
(Exact name of registrant as specified in its charter)

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

Delaware 76-0632293
(State or other jurisdiction of incorporation) (IRS Employer Identification No.)
370 17TH STREET, SUITE17th Street, Suite 900
DENVER, COLORADO
Denver, Colorado 80202
(Address
(Address of principal executive offices)
(Zip
(Zip Code)
303-595-3331
(Registrant's
(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][x] No [ ]

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

INDEX

TABLE OF CONTENTS

ITEM PAGE
- ---- ----

PART I. FINANCIAL INFORMATION (UNAUDITED)
Item 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
CONSOLIDATED STATEMENTS OF OPERATIONS
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED BALANCE SHEETS
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Item 2. Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations.................. 12Operations
Item 3. Quantitative and Qualitative Disclosure about Market Risks............................................. 18

Risks
PART II. OTHER INFORMATION
Item 1. Legal Proceedings...................................................................................... 20Proceedings
Item 6. Exhibits and Reports on Form 8-K....................................................................... 20
Signatures............................................................................................. 21
8-K
SIGNATURES
364-Day Credit Agreement
DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2002
INDEX
Item Page
PART I. FINANCIAL INFORMATION (UNAUDITED)
1. Financial Statements 1
Consolidated Statements of Operations for the Three Months Ended March 31, 2002 and 2001 1
Consolidated Statements of Comprehensive (Loss) Income for the Three Months Ended March 31, 2002 and 2001 2
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2002 and 2001 3
Consolidated Balance Sheets as of March 31, 2002 and December 31, 2001 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 16
PART II. OTHER INFORMATION
1. Legal Proceedings 21
6. Exhibits and Reports on Form 8-K 21
Signatures 22
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"“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"“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;

• our ability to access the debt and equity markets, which will depend on general market conditions and our credit ratings for our debt obligations;
• our use of derivative financial instruments to hedge commodity and interest rate risks;
• the level of creditworthiness of counterparties to transactions;
• changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gathering and processing industry;
i 3

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 timing and extent of changes in commodity prices, interest rates and demand for our services;
• weather and other natural phenomena;
• industry changes, including the impact of consolidations, and changes in competition;
• our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products; and
• the effect of accounting policies issued periodically by accounting standard-setting bodies.
In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described.
ii 4

PART I. FINANCIAL INFORMATION

ITEM
Item 1. FINANCIAL STATEMENTS

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

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
============ ============ ============ ============
OPERATIONS
(Unaudited)
(In Thousands)
THREE MONTHS ENDED,
MARCH 31,
2002 2001
OPERATING REVENUES:
Sales of natural gas and petroleum products $ 1,175,524 $ 2,381,883
Sales of natural gas and petroleum products—affiliates 308,836 940,299
Transportation, storage and processing 69,577 57,890
Total operating revenues 1,553,937 3,380,072
COSTS AND EXPENSES:
Purchases of natural gas and petroleum products 1,204,684 2,699,236
Purchases of natural gas and petroleum products—affiliates 100,649 313,263
Operating and maintenance 107,960 89,491
Depreciation and amortization 73,759 66,856
General and administrative 36,696 28,217
General and administrative—affiliates 2,461 4,189
Net loss (gain) on sale of assets 5,188 (868 )
Total costs and expenses 1,531,397 3,200,384
OPERATING INCOME 22,540 179,688
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES 6,070 5,176
INTEREST EXPENSE 43,309 42,017
(LOSS) INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE (14,699 ) 142,847
INCOME TAX EXPENSE 2,301 58
(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE (17,000 ) 142,789
CUMULATIVE EFFECT OF ACCOUNTING CHANGE — (411 )
NET (LOSS) INCOME (17,000 ) 142,378
DIVIDENDS ON PREFERRED MEMBERS’ INTEREST 7,125 7,125
(DEFICIT) EARNINGS AVAILABLE FOR MEMBERS’ INTEREST $ (24,125 ) $ 135,253
See Notes to Consolidated Financial Statements.
1 5

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

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

(Unaudited)
(In Thousands)
THREE MONTHS ENDED,
MARCH 31,
2002 2001
NET (LOSS) INCOME $ (17,000 ) $ 142,378
OTHER COMPREHENSIVE (LOSS) INCOME:
Cumulative effect of change in accounting principle — 6,626
Foreign currency translation adjustment (2,344 ) (912 )
Net unrealized losses on cash flow hedges (57,100 ) (18,202 )
Reclassification into earnings (18,534 ) 16,994
Total other comprehensive (loss) income (77,978 ) 4,506
TOTAL COMPREHENSIVE (LOSS) INCOME $ (94,978 ) $ 146,884
See Notes to Consolidated Financial Statements.
2 6

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

CASH FLOWS FROM OPERATING ACTIVITIES: Net income .................................................................... $ Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .............................................. Deferred income taxes ...................................................... Change in derivative fair value ............................................ Equity in earnings of unconsolidated affiliates ............................ Loss (gain) on sale of assets .............................................. Change in operating assets and liabilities (net of effects of acquisitions) which provided (used) cash: Accounts receivable ........................................................ Accounts receivable--affiliates ............................................ Inventories ................................................................ Unrealized gains on mark-to-market transactions ............................ Other current assets ....................................................... Other noncurrent assets .................................................... Accounts payable ........................................................... Accounts payable--affiliates ............................................... Accrued interest payable ................................................... Unrealized losses on mark-to-market transactions ........................... Other current liabilities .................................................. Other long term liabilities ................................................

Net cash provided by operating activities ...............................

CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions and other capital expenditures ................................... Investment expenditures ....................................................... Investment distributions ...................................................... Proceeds from sales of assets .................................................

Net cash used in investing activities ...................................

CASH FLOWS FROM FINANCING ACTIVITIES: Net change in advances--parents ............................................... Distributions to parents ...................................................... Proceeds from issuing debt .................................................... Payment of debt ............................................................... Short term debt--net ..........................................................

Net cash used in financing activities ...................................

NET CHANGE IN CASH AND CASH EQUIVALENTS .......................................... CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ...................................

CASH AND CASH EQUIVALENTS, END OF PERIOD ......................................... $

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Cash paid for interest (net of amounts capitalized) ............. $

(Unaudited)
(In Thousands) SIX MONTHS ENDED, JUNE 30, ---------------------------- 2001 2000 ------------ ------------ 258,020 $ 454,129 134,717 105,359 (338) (308,230) 8,128 -- (16,080) (14,707) (988) 337 615 (142,339) 163,184 (93,679) 15,274 (39,532) (62,742) (56,631) 2,879 43,583 (11,974) (2,232) (53,227) 343,541 (28,537) 6,053 5,726 318 29,522 50,461 (20,072) (7,473) (4,659) (14,215) ------------ ------------ 419,448 324,743 ------------ ------------ (308,695) (214,269) (1,114) (1,327) 28,538 12,093 18,852 14,220 ------------ ------------ (262,419) (189,283) ------------ ------------ (2,182) 25,370 (129,687) (2,744,319) 248,358 -- (47,556) (205,610) (226,428) 2,790,900 ------------ ------------ (157,495) (133,659) ------------ ------------ (466) 1,801 1,553 792 ------------ ------------ 1,087 $ 2,593 ============ ============ 30,878 $ 44,180 enter>
THREE MONTHS ENDED,
MARCH 31,
2002 2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income $ (17,000 ) $ 142,378
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 73,759 66,856
Deferred income taxes (520 ) —
Change in fair value of derivative instruments 6,509 (11,197 )
Equity in earnings of unconsolidated affiliates (6,070 ) (5,176 )
Net loss (gain) on sale of assets 5,188 (868 )
Change in operating assets and liabilities (net of effects of acquisitions) which provided (used) cash:
Accounts receivable (26,782 ) 89,884
Accounts receivable—affiliates 194,256 (97,851 )
Inventories 10,663 46,695
Net unrealized mark-to-market and hedging transactions 46,564 (2,249 )
Other current assets 2,852 1,836
Other noncurrent assets (590 ) (12,692 )
Accounts payable (148,780 ) 108,781
Accounts payable—affiliates (12,244 ) (10,170 )
Accrued interest payable (31,757 ) (30,230 )
Other current liabilities 1,848 (26,310 )
Other long term liabilities (1,962 ) (5,589 )
Net cash provided by operating activities 95,934 254,098
CASH FLOWS FROM INVESTING ACTIVITIES:
Other capital expenditures (106,785 ) (63,118 )
Investment expenditures (3,463 ) (1,114 )
Investment distributions 12,488 16,024
Proceeds from sales of assets — 18,551
Net cash used in investing activities (97,760 ) (29,657 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to members (45,672 ) (127,561 )
Proceeds from issuing debt — 250,000
Short term debt—net 43,580 (346,410 )
Net cash used in financing activities (2,092 ) (223,971 )
EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH 2,344 912
NET (DECREASE) INCREASE IN CASH (1,574 ) 1,382
CASH, BEGINNING OF PERIOD 4,906 1,553
CASH, END OF PERIOD $ 3,332 $ 2,935
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION — Cash paid for interest (net of amounts capitalized) $ 76,357 $ 71,131
See Notes to Consolidated Financial Statements.
3 7

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

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

(Unaudited)
(In Thousands)
MARCH 31, DECEMBER 31,
2002 2001
ASSETS
CURRENT ASSETS:
Cash $ 3,332 $ 4,906
Accounts receivable:
Customers, net 575,769 520,118
Affiliates 36,265 230,521
Other 107,941 136,810
Inventories 72,272 82,935
Unrealized gains on trading and hedging transactions 90,301 180,809
Other 7,358 9,060
Total current assets 893,238 1,165,159
PROPERTY, PLANT AND EQUIPMENT, NET 4,726,854 4,711,960
INVESTMENT IN AFFILIATES 138,315 132,252
INTANGIBLE ASSETS:
Natural gas liquids sales and purchases contracts, net 91,010 94,019
Goodwill, net 421,176 421,176
Total intangible assets 512,186 515,195
UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS 14,051 19,095
OTHER NONCURRENT ASSETS 87,138 86,548
TOTAL ASSETS $ 6,371,782 $ 6,630,209
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable:
Trade $ 492,895 $ 620,094
Affiliates 13,376 25,620
Other 55,333 76,914
Short term debt 256,535 212,955
Unrealized losses on trading and hedging transactions 108,723 84,811
Accrued interest payable 25,660 57,417
Accrued taxes other than income 11,524 24,646
Distributions payable to members 17,490 45,672
Other 117,664 102,694
Total current liabilities 1,099,200 1,250,823
DEFERRED INCOME TAXES 14,566 14,362
LONG TERM DEBT 2,232,876 2,235,034
UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS 41,820 25,188
OTHER LONG TERM LIABILITIES 13,883 15,845
MINORITY INTERESTS 135,989 135,915
PREFERRED MEMBERS’ INTEREST 300,000 300,000
COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS’ EQUITY:
Members’ interest 1,709,290 1,709,290
Retained earnings 854,091 895,707
Accumulated other comprehensive (loss) income (29,933 ) 48,045
Total members’ equity 2,533,448 2,653,042
TOTAL LIABILITIES AND MEMBERS’ EQUITY $ 6,371,782 $ 6,630,209
See Notes to Consolidated Financial Statements.
4 8

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

(Unaudited)
1. GENERALGeneral
Duke Energy Field Services, LLC (with its consolidated subsidiaries, "the Company"“the Company” or "Field“Field Services LLC"LLC”) operates in the midstream natural gas gathering, processing, 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)(“NGLs”) fractionation, transportation, marketing and trading.
2. ACCOUNTING POLICIES

Accounting Policies
Consolidation - —The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after the elimination ofeliminating significant intercompany transactions and balances. Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not operate these investments and as a result does not have the ability to exercise control. 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 recognizedrecorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions, as
appropriate.Transactions. On the date the swap, futuresthat swaps or option contracts are entered into, the Company designates the derivative as either held for trading (trading instruments),; as a hedge of the fair value of a recognized asset, or liability or of an
unrecognized firm commitment (fair value hedges), or; as a hedge of a forecasted transaction or future cash flows (cash flow hedges).

The; or leaves the derivative undesignated and marks it to market.
For hedge contracts, the Company also formally assesses, both at the hedge'shedge contracts inception and on an ongoing basis, whether the derivatives that are used in hedging
transactions arehedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. The Company currently excludes the extrinsictime value of the options when assessing hedge effectiveness.
When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market price and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Commodity Trading - Prior to the settlement— A favorable or unfavorable price movement of any derivative contract held for trading purposes a favorable or unfavorable price movement is reported as Purchases of Natural Gas and Petroleum Products Purchases in the Consolidated Statements of Income.Operations. An offsetting amount is recorded gross 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.Operations. Similarly, when a contract to purchase energy is physically settled, the purchase price is included as Purchases of Natural Gas and Petroleum Products Purchases in the Consolidated Statements of Income.Operations. If a contract is not physically settled, the unrealized gain or unrealized loss onin the balance sheetConsolidated Balance
5
Sheets is reclassified to a receivable or payable account. For income statement purposes, financial settlement has no net operating income presentation effect on the Consolidated Statements of Operations.
Commodity Cash Flow Hedges — The effective portion of the change in fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Comprehensive (Loss) Income as Other Comprehensive (Loss) Income (“OCI”) until earnings are affected by the hedged item. Settlement amounts of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until earnings are affected by the hedged item, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were accumulated in OCI will be immediately recognized in current-period earnings.
Commodity Fair Value Hedges -— Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge and the underlying physical
transaction are included in the Consolidated Statements of IncomeOperations as Sales of Natural Gas and Petroleum Products and Purchases of 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.appropriate. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated StatementStatements of IncomeOperations 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
Interest Rate Fair Value Hedges -— The fair valueCompany enters into interest rate swaps to convert some 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 changeits fixed-rate long term debt to floating-rate long term debt. Hedged items in fair value hedges are marked to market with the respective derivative instruments. Accordingly, the Company’s hedged fixed-rate debt is carried at fair value. The terms of the derivative instrument is
included in Other Comprehensive Income (OCI) until earnings are affectedoutstanding swap match those of the associated debt which permits the assumption of no ineffectiveness, as defined 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

5
9

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)(“SFAS”) No. 133, "Accounting“Accounting for Derivative Instruments and Hedging Activities," on January 1, 2001. In
accordance withActivities.” As such, for the transition provisionslife 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
OCIswap no ineffectiveness 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.

recognized.
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)(“Duke Energy”) and Phillips Petroleum Company (Phillips)(“Phillips”) based on allocated taxable income. The distribution isdistributions are 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— The Company adopted SFAS No. 142, "Goodwill“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.

6
10

SFAS No. 142 is effective for fiscal years beginning after December 15,
2001 and will be adopted by the Company as ofAssets,” on 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 beare subject to a fair-value-based annual impairment assessment as described byassessment. The Company did not recognize any impairments due to the new standard.implementation of SFAS No. 142142. The standard also requires acquiredcertain identifiable intangible assets to be recognized separately and amortized as appropriate. No such intangibles have been identified by the Company at transition.
6
The following table shows what net income would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods.
For The Three
Months Ended
March 31,
2002 2001
(In Thousands)
Reported net (loss) income $ (17,000 ) $ 142,378
Add: Goodwill amortization — 1,492
Adjusted net (loss) income $ (17,000 ) $ 143,870
The changes in the carrying amount of goodwill for the three months ended March 31, 2002 and March 31, 2001 are as follows:
Goodwill (In Thousands)
Balance Acquired Balance
December 31, 2001 Goodwill Other March 31, 2002
Natural gas gathering, processing, transportation, marketing and storage $ 394,054 $ — $ — $ 394,054
NGL fractionation, transportation, marketing and trading 27,122 — — 27,122
Total consolidated $ 421,176 $ — $ — $ 421,176
Balance Acquired Balance
December 31, 2000 Goodwill Other March 31, 2001
Natural gas gathering, processing, transportation, marketing and storage $ 376,195 $ — $ (1,492 ) $ 374,703
NGL fractionation, transportation, marketing and trading — — — —
Total consolidated $ 376,195 $ — $ (1,492 ) $ 374,703
The Company expects thatadopted SFAS No. 144, “Accounting for the adoptionImpairment or Disposal of Long-Lived Assets,” on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions of SFAS No. 142 will have121, but significantly change the criteria for classifying an asset as held-for-sale. The impact on future financial statements dueof adopting SFAS No. 144 was not material 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.

Company.
Reclassifications -— Certain prior period amounts have been reclassified in the Consolidated Financial Statements and Note 6 to conform to the current presentation.
3. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND CREDIT RISK

Derivative Instruments, Hedging Activities and Credit Risk
Commodity price risk -— The Company'sCompany’s principal operations of gathering, processing, transportation and storage of natural gas, and the accompanying operations of processing, fractionation, transportation, trading and marketing of natural gas liquidsNGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs and natural gas liquids.gas. 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'sCompany’s subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and
7
facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to suchthese products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and salessale of commodity-based instruments.
Corporate economic risks— The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.
Counterparty risks— The Company sells NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGL sales are made at market-based prices, including approximately 40% of NGL production that is committed to Phillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015 . This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. 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. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. However, these transactions are generally subject to margin agreements with the majority of our counterparties.
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, capital expenditures and tax distributions. The Company’s primary corporate hedging goals include (1) maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; (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 NGLs.
The Company uses natural gas, crude oil and NGL swaps and options to hedge the impact of market fluctuations in the price of natural gas liquids and other energy-related products. For the three months ended March 31, 2002, the Company recognized a net gain of $7.4 million, of which a $5.9 million loss represented the total ineffectiveness of all cash flow hedges and an $18.5 million gain represented the total derivative settlements. The time value of the options, a recognized $5.2 million loss for the three months ended March 31, 2002, 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 Operations. 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 not probable of 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 March 31, 2002, $15.8 million of the deferred net losses on derivative instruments accumulated in OCI are expected to be reclassified as earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in OCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is three years.
8
Commodity fair value hedges— The Company uses 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 (New York Mercantile Exchange or index based).
For the three months ended March 31, 2002, the gains or losses representing the ineffective portion of the Company’s fair value hedges were not material. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.
Interest rate fair value hedge— In October 2001, the Company entered an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. The swap meets conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swap no ineffectiveness will be recognized. As of March 31, 2002, the fair value of the interest rate swap of ($7.4) million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.
Commodity Derivatives — Trading— The trading of energy related products and services exposes the Company to the fluctuations in the market values of traded instruments. The Company manages its traded instrument portfolio with strict policies which limit exposure to market risk and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement.

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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11

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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12

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

Financing
Credit Facility with Financial Institutions - —On March 30, 2001,29, 2002, the Company entered into a new credit facility (the "New Facility"“New Facility”). The New Facility replaces the credit facility that matured on March 30, 2001.29, 2002. The New Facility is used to support the Company'sCompany’s commercial paper program and for working capital and other general corporate purposes. The New Facility matures on March 29, 2002,28, 2003, however, any outstanding loans under the New Facility at maturity may, at the Company'sCompany’s option, be converted to a one-year term loan. The New Facility is a $675.0$650.0 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'sCompany’s option and based on the Company'sCompany’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,March 31, 2002, there were no borrowings against the New Facility.

Debt Securities - On February 2, 2001,
At March 31, 2002 the Company issued $250.0had a $30.0 million inoutstanding Irrevocable Standby Letter of Credit expiring March 31, 2003.
At March 31, 2002 the Company was the guarantor of approximately $25.6 million of 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
optionassociated with an unconsolidated subsidiary. Assets of the Company.unconsolidated subsidiary are pledged as collateral for the debt.
5. Commitments and Contingent Liabilities
Litigation— The midstream natural gas industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. The Company used the proceeds from the issuanceand its subsidiaries are currently named as defendants in some 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
9
cases. Management believes the Company and UPRCits subsidiaries have meritorious defenses to these cases, and triggered Williams' preferential purchase right. On November 22, 1999, the
District Court granted UPRC and the Company's motion for

9
13

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
Companytherefore will continue to negotiate with NMEDdefend them vigorously. However, these class actions can be costly and time consuming to resolve all issues relating to
the alleged violations.defend.
Management believes that the final depositiondisposition 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
6. 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'sCompany’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)(“EBITDA”) and earnings before interest and taxes (EBIT)(“EBIT”) are the performance measures utilizedused 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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14
The following table sets forth the Company'sCompany’s segment information.
For The Three
Months Ended
March 31,
2002 2001
(In Thousands)
Operating revenues:
Natural gas $ 904,917 $ 2,743,413
NGLs 926,873 1,227,830
Intersegment (a) (277,853 ) (591,171 )
Total operating revenues $ 1,553,937 $ 3,380,072
Margin:
Natural gas $ 232,549 $ 355,757
NGLs 16,055 11,816
Total margin $ 248,604 $ 367,573
Other operating costs:
Natural gas $ 110,747 $ 87,750
NGLs 2,401 873
Corporate 39,157 32,406
Total other operating costs $ 152,305 $ 121,029
Equity in earnings of unconsolidated affiliates:
Natural Gas $ 5,649 $ 4,688
NGLs 421 488
Total equity in earnings of unconsolidated affiliates $ 6,070 $ 5,176
EBITDA (b):
Natural gas $ 127,451 $ 272,695
NGLs 14,075 11,431
Corporate (39,157 ) (32,406 )
Total EBITDA $ 102,369 $ 251,720
Depreciation and amortization:
Natural gas $ 69,187 $ 63,481
NGLs 3,318 2,295
Corporate 1,254 1,080
Total depreciation and amortization $ 73,759 $ 66,856
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For The Three
Months Ended
March 31,
2002 2001
(In Thousands)
EBIT (b): Natural gas $ 58,264 $ 209,214
NGLs 10,757 9,136
Corporate (40,411 ) (33,486 )
Total EBIT $ 28,610 $ 184,864
Corporate interest expense $ 43,309 $ 42,017
(Loss) income before income taxes:
Natural gas $ 58,264 $ 209,214
NGLs 10,757 9,136
Corporate (83,720 ) (75,503 )
Total (loss) income before income taxes $ (14,699 ) $ 142,847
Capital Expenditures:
Natural gas $ 103,010 $ 60,885
NGLs 179 540
Corporate 3,596 1,693
Total capital expenditures $ 106,785 $ 63,118
As Of
March 31, December 31,
2002 2001
(In Thousands)
Total assets:
Natural gas $ 5,333,867 $ 5,326,889
NGLs 229,208 258,177
Corporate (c) 808,707 1,045,143
Total assets $ 6,371,782 $ 6,630,209

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

Operating revenues:
Natural(a) Intersegment sales represent sales of NGLs from the natural gas ................................................... $ 1,211,835 $ 1,675,793 $ 3,955,248 $ 2,575,007segment to the 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 earningssegment at either index prices or weighted average prices of unconsolidated affiliates:
Natural Gas ................................................... $ 10,458 $ 7,374 $ 16,122 $ 13,888
NGLs .......................................................... 446 574 (42) 819
------------ ------------ ------------ ------------
Total equity in earningsNGLs. Both measures 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 intersegment sales are effectively based on current economic market conditions.
(b) EBITDA ............................................ $ 224,158 $ 212,094 $ 475,878 $ 312,574
============ ============ ============ ============
Depreciationconsists of income from continuing operations before interest expense, income tax expense, 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)
------------ ------------ ------------ ------------
Totalexpense. EBIT .............................................. $ 156,297 $ 144,829 $ 341,161 $ 207,215
============ ============ ============ ============
Corporate interest expense ....................................... $ 40,375 $ 45,374 $ 82,392 $ 59,851
============ ============ ============ ============
Income beforeis equal to 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 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
============ ============ ============ ============

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15

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

Acquisitionsor 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 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
========== ========== ========== ==========
assets.

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

(a) Intersegment sales represent sales of NGLs from
7. Subsequent Event
In April 2002 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
notCompany filed 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'sshelf registration statement increasing its ability to service debtissue securities to $500.0 million. The shelf registration statement provides for the issuance of senior notes, subordinated notes 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
accountstrust preferred securities.
11
Item 2. Management’s Discussion and other assets.

8. SUBSEQUENT EVENTS

On July 10, 2001, the Company acquired additional interests in Mobile
Bay Processing Partners, Gulf Coast NGL Pipeline, L.L.C.Analysis of Financial Condition and Dauphin Island
Gathering Partners for approximately $67.4 million. As a resultResults 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

Operations
The following discussion details the material factors that affected our historical financial condition and results of operations during the three months ended March 31, 2002 and six months ended June 30, 2001 and 2000.2001. 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.

12
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
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)
• 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;
• 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
Effects of Commodity Prices
The Company is exposed to commodity prices as a result of being paid for certain services in the six months ended June 30, 2001,form of commodities rather than cash. For gathering services, the weighted average NGL
price (based on index pricesCompany receives fees from producers to bring natural gas from the Mont Belvieuwell head to the processing plant. For processing services, the Company either receives fees or commodities as payment for these services, depending on the type of contract. Under a percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of both the NGLs produced and Conway market hubs that
are weighted by our componentthe residue gas resulting from processing the natural gas. Under a keep-whole contract, the Company keeps all or a portion of the NGLs produced, but returns the equivalent British thermal unit (“Btu”) content of the gas back to the producer. Based on the Company’s current contract mix, the Company has a net long NGL position and location mix) was approximately $0.54 per
gallon. Historically, NGL prices have generally followedis sensitive to changes in NGL prices. The Company also has a net short residue gas position, however the short residue gas position is less significant than the long NGL position.
During 2001 and the first quarter of 2002, approximately 75% of our gross margin was generated by commodity sensitive arrangements and approximately 25% of our gross margin was generated by fee-based arrangements. The commodity exposure is actively managed by the Company as discussed below.
The midstream natural gas industry has been cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally correlated to the price of crude oil
prices. However,oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term the growth of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs and natural gas have been extremely volatile.
The depressed NGL and natural gas price environment experienced in 1998 prevailed during the first quarter of 2001,1999. However, during the last three quarters of 1999, NGL prices departed from this
trendincreased sharply as major crude oil exporting countries agreed to maintain crude oil production at predetermined levels and followedworld demand for crude oil and NGLs increased. The lower crude oil and natural gas prices in 1998 and early 1999 caused a significant
12
reduction in the sharpexploration activities of United States producers, which in turn had a significant negative effect on natural gas volumes gathered and processed in 1999. Due to reduced supply and strong demand, natural gas and NGL prices increased throughout 2000 along with renewed strength in drilling activity.
The slowing economy combined with an increase in supply availability resulting from increased drilling levels drove declines in both crude oil and natural gas prices. Despite the impact
of the natural gas price spike experiencedprices during the final two quarters of 2001. The dramatic decline in NGL prices is attributed to the drop in crude oil prices in addition to a decline in the correlation between NGL prices and crude oil.
During the last two quarters of 2001 and first quarter we expect
thatof 2002, the relationship or correlation between crude oil value and NGL prices willremained depressed. We generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. 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.United States economic growth. We believe that weather will be the strongest determinant of near-termnear term natural gas prices. PriceThe price increases in crude oil, NGLs and natural gas have continued to spurexperienced during 2000 and the first two quarters of 2001 spurred increased natural gas drilling activity. For example, the average number of active drilling rigs in North America has increased by approximately 35%19% from approximately 1,1691,263 in June 2000 to approximately
1,5731,497 in June 2001. ThisThe decline in commodity prices over the final two quarters of 2001 and first quarter of 2002 negatively effected drilling activity increase is expectedas the average number of active rigs in North America declined to 1,136 during the first quarter of 2002. We expect that continued pressure from reduced commodity prices on drilling will negatively impact North American drilling activity in the short term. We expect lower drilling levels over a sustained period will have a positivenegative effect on natural gas volumes gathered and processedprocessed.
To better address the risks associated with volatile commodity prices, the Company employs a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Our first quarter 2001 and 2002 results of operations include a hedging loss of $14.6 million and gain of $7.4 million, respectively. The hedging loss observed 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
secondfirst quarter of 2001. These price increases yielded average prices2001 relates to hedges placed during periods of $.48 per
gallon and $4.67 per million Btus, respectively, as compared with $.47 per
gallon and $3.47 per million Btus forincreasing prices. The slight gain recognized in the secondfirst 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 mainly2002 is the result of hedging gains achieved as a result of a sharp decline in commodity prices during the Decemberthird and fourth quarters of 2001 continuing through the first quarter of 2002.
Results of Operations
Three Months Ended,
March 31,
2002 2001
Operating revenues:
Sales of natural gas and petroleum products $ 1,484,360 $ 3,322,182
Transportation, storage and processing 69,577 57,890
Total operating revenues 1,553,937 3,380,072
Purchases of natural gas and petroleum Products 1,305,333 3,012,499
Gross margin 248,604 367,573
Equity earnings of unconsolidated affiliates 6,070 5,176
Total gross margin and equity earnings of Unconsolidated affiliates(1) $ 254,674 $ 372,749
(1) Gross margin and equity in earnings (“Gross Margin”) consists of income from continuing operations
13
before operating and general and administrative expense, interest expense, income tax expense, and depreciation and amortization expense plus equity earnings of unconsolidated affiliates. Gross margin as defined is not a measurement presented in accordance with generally accepted accounting principles. You should not consider this measure in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as an isolated measure of our profitability or liquidity. Gross margin is included as a supplemental disclosure because it may provide useful information regarding the impact of key drivers such as commodity prices and supply contract mix on the Company’s earnings.
Three months ended March 31, 2000 purchase of the Guadalupe Pipeline System,
increased fee based processing and storage activities and the May 1,2002 compared with three months ended March 31, 2001
purchase of Canadian Midstream Services, Ltd. A $1.2
Gross Margin.Gross Margin decreased $118.0 million, hedging lossor 32% from $372.7 million in the secondfirst 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 $363.6to $254.7 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
2001.2002. This decrease was primarily the result of issuancelower NGL prices of commercial paperapproximately $165.0 million (net of hedging) due to a $.29 per gallon decrease in average NGL prices. These decreases were partially offset by approximately $36.0 million due to a $4.77 per million British thermal unit (“Btu”) decrease in natural gas prices. These price changes yielded average prices of $.31 per gallon of NGLs and $2.32 per million Btus of natural gas, respectively, as compared with $.60 per gallon and $7.09 per million Btus during the subsequent third quarter 2000same period 2001.
Partially offsetting the decrease associated with commodity prices were increases of approximately $15.3 million attributable to the combination of our acquisitions of Canadian Midstream, northeast propane terminal and marketing assets, and additional interests in three Offshore Gulf of Mexico partnerships.
Gross margin associated with the natural gas gathering, processing, transportation and storage segment decreased $122.2 million, or 34%, from $360.4 million to $238.2 million, mainly as a result of the lower NGL prices. Commodity sensitive processing arrangements accounted for approximately $130.0 million (net of hedging) of this decrease due mainly to the $.29 per gallon decrease in average NGL prices. This reduction was the result of the interaction of commodity prices and our gas supply arrangements.
NGL production during the first quarter of 2002 increased 17,500 barrels per day, or 5%, from 371,100 barrels per day to 388,600 barrels per day, and natural gas transported and/or processed increased 0.2 trillion Btus per day, or 2%, from 8.2 trillion Btus per day to 8.4 trillion Btus per day. The primary cause of the increase in NGL production was the increase in keep-whole processing activity due to more profitable processing margins in 2002.
Costs and Expenses.Operating and maintenance expenses increased $18.5 million, or 21%, from $89.5 million in the first quarter of 2001 to $108.0 million in the same period of 2002. This increase is primarily the result of acquisitions and expanded business activity. General and administrative expenses increased $6.8 million, or 21%, from $32.4 million in the first quarter of 2001 to $39.2 million in the same period of 2002. This increase is primarily the result of increased allocated cost from Duke Energy due to increased service levels.
Depreciation and amortization increased $6.9 million, or 10%, from $66.9 million in the first quarter of 2001 to $73.8 million in the same period of 2002. This increase was due primarily to acquisitions, ongoing capital expenditures for well connections and facility maintenance and enhancements.
Interest.Interest expense increased $1.3 million, or 3%, from $42.0 million in the first quarter of 2001 to $43.3 million in the same period of 2002. This increase was primarily the result of higher outstanding debt offerings.

levels, partially offset by lower interest rates.
Income Taxes. At March 31, 2000, the PredecessorThe Company converted tois structured as 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

14
18

deferred tax liability of $327.0 million was eliminated and a correspondingFirst quarter 2002 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 $23.4expense of $2.3 million from $92.2 million for
the second quarter 2000 to $115.6 million for the same period in 2001. This
increase was primarilyis mainly 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 ofother miscellaneous taxes associated tax-paying subsidiaries.
Net Income.Net 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 $1.9decreased $159.4 million from $239.8$142.4 million forin the secondfirst quarter 2000of 2001 to $241.7a loss of $17.0 million forin the same period in 2001.first quarter of 2002. This increasedecrease was primarilylargely the result of higher earnings for thedecreased NGL prices and
14
increases in operating and general partnership interest in
TEPPCO, partiallyadministrative expenses, slightly offset by the interaction of our gas purchase contracts with
higherlower natural gas prices. Cost reduction initiativesprices and acquisition activity.
Liquidity and Capital Resources
Operating Cash Flows
Net cash provided by operating activity decreased centralized
service charges from our parents contributed $7.3$158.2 million to EBITDA duringin the secondfirst 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 revenues2002 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 infirst quarter 2001. The primary causedecrease is primarily due to a reduction in net income 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$159.4 million. The reduction in net income is largely due to significantly lower NGL prices.

Commodity prices also contributed to higher revenues. Weighted average
NGL prices, based on our component product mix, were approximately $.05 per
gallon higher
Price volatility in crude oil, NGLs and natural gas prices were approximately $2.89 per million
British thermal units (Btus) higherhave a direct impact on our use and generation of cash from operations.
Investing Cash Flows
Our capital expenditures consist of expenditures for the six months ended June 30, 2001.
These price increases yielded average pricesacquisitions and construction 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 withadditional gathering transportation, storage,systems, processing feesplants, fractionators and other increased $38.8facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the period ended March 31, 2002, we spent approximately $106.8 million or
48%, from $80.7 millionon capital expenditures. These capital expenditures were primarily for the six months ended June 30, 2000 to $119.5 million
for the same period in 2001, mainly as a resultplant expansions, well connections and plant upgrades.
Our level 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
19

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/enhancementsacquisitions and acquisitions.

Equity Earnings. Equity earningsconstruction depends on many factors, including industry conditions, the availability of unconsolidated affiliates increased
$1.4 million, or 10%,attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from $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 fromoperations and borrowings available under 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 program, our credit facilities or other available sources of financing.
Financing Cash Flows
Bank Financing and the subsequent third quarter 2000 and first quarter 2001 debt
offerings.

Income Taxes. AtCommercial Paper
In 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, 2001,2002, we entered into a new$650.0 million credit facility (the "New
Facility"). The New Facility replaces (“the credit facility that matured on March
30, 2001.Facility”), of which $150.0 million can be used for letters of credit. The New Facility is used to support the Company'sour commercial paper program and for working capital and other general corporate purposes. The New
Facility matures on March 29, 2002,28, 2003, however, any outstanding loans under the New
Facility at maturity may, at the Company'sour 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 Companyus 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'sour option, and based on the Company's current debt
rating, either (1) LIBORthe London Interbank Offered Rate (“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,March 31, 2002, there were no borrowings against the New Facility.

On February 2, 2001, the Company issued $250.0
At March 31, 2002 we had a $30.0 million outstanding Irrevocable Standby Letter of Credit expiring March 31, 2003.
At March 31, 2002 we had $256.5 million in outstanding commercial paper, with maturities ranging from one day to 19 days and annual interest rates ranging from 2.10% to 2.20%. At no time did the amount of our outstanding commercial paper exceed the available amount under the Facility. In the future, our debt securities.levels will vary depending on our liquidity needs, capital expenditures and cash flow.
In April 2002 we filed a shelf registration statement increasing our ability to issue securities to $500.0 million. 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 fromshelf registration statement provides for the issuance of thesenior notes, to repay
short term debt.subordinated notes and trust preferred securities.
15
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,the 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
Contractual Obligations and Commercial Commitments
As part of expenditures for acquisitions and
construction of additional gathering systems, processing plants, fractionatorsour normal business, we are a party to various financial guarantees, performance guarantees and other facilitiescontractual commitments to extend guarantees of credit and infrastructure in additionother assistance to well connectionsvarious subsidiaries, investees and refurbishmentother third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of us having to honor our existing facilities. Forcontingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the six months ended June 30,
2001,occurrence of certain future events. We would record a reserve if events occurred that required that one be established.
At March 31, 2002 we spent approximately $308.7 million on capital expenditures. On April
30, 2001,were 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 priceguarantor of approximately $162.0 million. The purchase price included the assumption$25.6 million of debt associated with an unconsolidated subsidiary. Assets 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 activitiesunconsolidated subsidiary are pledged as collateral 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
pricesdebt.
Item 3. Quantitative 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.Qualitative Disclosure about Market Risks
Risk 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

17
21

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."

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 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 RISKSPolicies
We are exposed to market risks associated with commodity prices, credit exposure, interest rates commodity prices, and equity prices.foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. The Company'sOur Risk Management Committee (“RMC”) oversees risk exposure including fluctuations in commodity prices. The RMC ensures that proper policies and procedures are in place to adequately manage our commodity price risks and is responsible for the overall approvalmanagement of commodity price and other risk exposures.
Mark-to-Market Accounting (“MTM accounting”)— Under the MTM accounting method, an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in earnings during the current period. This accounting method has been used by other industries for many years, and in 1998 the Financial Accounting Standards Board’s (“FASB”) Emerging Issues Task Force (“EITF”) issued guidance 98-10 that required MTM accounting for energy trading contracts. MTM accounting reports contracts at their “fair value,” (the value a willing third party would pay for the particular contract at the time a valuation is made).
When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using pricing models or matrix pricing based on contracts with similar terms and risks. This is validated by an internal group independent of the Company’s trading area. Holders of thinly traded securities or investments (mutual funds, for example) use similar techniques to price such holdings. Correlation and volatility are two significant factors used in the computation of fair values. We validate our internally developed fair values by comparing locations/durations that are highly correlated, using forecasted market intelligence and mathematical extrapolation techniques. While we use industry best practices to develop our pricing models, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values, income recognition and realization in future periods.
Hedge Accounting— Hedging typically refers to the mechanism that the Company uses to mitigate the impact of volatility associated with price fluctuations. Hedge accounting treatment is used when we contract to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with the anticipated
16
physical sale or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when the Company holds firm commitments or asset positions, and enters into transactions that “hedge” the risk that the price of natural gas may change between the contract’s inception and the physical delivery date of the commodity ultimately affecting the underlying value of the firm commitment or position (fair value hedge). While the majority of our hedging transactions are used to protect the value of future cash flows related to our physical assets, to the extent the hedge is effective, we recognize in earnings the value of the contract when the commodity is purchased or sold, or the hedged transaction occurs or settles.
Commodity Price Risk
We are exposed to the impact of market 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 personnelfluctuations primarily in the Company's marketingprice of NGLs 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.

18
22

COMMODITY PRICE RISK

We are subject to significant risks due to fluctuations in commodity
prices, primarily with respect to the prices of NGLsnatural gas that we own as a result of our processing activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and options for non-trading activity (primarily hedge strategies). (See Notes 2 and 3 to the Consolidated Financial Statements.)
Commodity Derivatives — Trading— The risk in the commodity trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (“DER”) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading portfolio (which includes all trading contracts not designated as hedge positions) on a monthly and annual basis. These measures include limits on the nominal size of positions and periodic loss limits.
DER computations are based on a historical simulation, which uses price movements over a specified period (generally ranging from seven to 14 days) to simulate forward price curves in the energy markets to estimate the potential favorable or unfavorable impact of one day’s price movement on the existing portfolio. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for crude oil, NGLs, gas and other energy-related products. DER computations utilize several key assumptions, including 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DER amounts for commodity derivatives instruments held for trading purposes are shown in the following table.
Daily Earnings at Risk
Estimated Average Estimated Average High One-Day Low One-Day
One-Day Impact One-Day Impact Impact on EBIT Impact on EBIT
on EBIT for the on EBIT for the for the three for the three
three months ended three months ended months ended months ended
March 31, 2002 March 31, 2001 March 31, 2002 March 31, 2002
(In millions)
Calculated DER $ 2.3 $ 1.5 $ 4.8 $ 1.3
DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests may be employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.
Our exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of our trading instruments during the three months ending March 31, 2002.
17
Changes in Fair Value of Trading Contracts
(In millions)
Fair value of contracts outstanding at the beginning of the period $ 37.4
Contracts realized or otherwise settled during the period (51.6 )
Net mark-to-market changes in fair values 4.7
Fair value of contracts outstanding at the end of the period $ (9.5 )
For the three months ended March 31, 2002, the unrealized net loss recognized in operating income was $46.9 million as compared to a $6.1 million gain for the same period in 2001. The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values. At March 31, 2002, we held cash or letters of credit of $7.1 million to secure such future performance, and had no amounts deposited with counterparties. Collateral amounts held or posted vary depending on the value of the underlying contracts and cover trading and hedging contracts outstanding. We may be required to return held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions.
When available, we use observable market prices for valuing our trading instruments. When quoted market prices are not available, we use established guidelines for the valuation of these contracts. We may use a variety of reasonable methods to assist in determining the valuation of a trading instrument, including analogy to reliable quotations of similar trading instruments, pricing models, matrix pricing and other formula-based pricing methods. These methodologies incorporate factors for which published market data may be available. All valuation methods employed by us are approved by an internal corporate risk management organization independent of the trading function and are applied on a consistent basis.
The following table shows the fair value of our trading portfolio as of March 31, 2002.
Fair Value of Contracts as of March 31, 2002
Maturity in
Maturity in Maturity in Maturity in 2005 and
Sources of Fair Value 2002 2003 2004 Thereafter Total Fair Value
(In millions)
Prices supported by quoted market prices and other external sources $ 4.7 $ (3.1 ) $ (0.4 ) $ (2.9 ) $ (1.7 )
Prices based on models and other valuation methods 0.2 (4.0 ) (4.2 ) 0.2 (7.8 )
Total $ 4.9 $ (7.1 ) $ (4.6 ) $ (2.7 ) $ (9.5 )
The “prices supported by quoted market prices and other external sources” category includes Duke Energy Field Services’ New York Mercantile Exchange (“NYMEX”) swap positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes our forward positions and options in natural gas and natural gas basis swaps at points for which over-the-counter (“OTC”) broker quotes are available. On average, OTC quotes for natural gas forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas options extend 12 months into the future, on average. We value these positions against internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.
The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. It is important to understand that in certain instances structured transactions can
18
be decomposed and modeled by us as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore have been included in this category due to the complex nature of these transactions.
Hedging Strategies— We are exposed to market fluctuations in the prices of energy commodities related to natural gas gathering, processing and marketing activities. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. In accordance with SFAS No. 133, our primary use of commodity derivatives is to hedge the output and production of assets we physically own. Contract terms are up to four years, however, since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by us, to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in OCI or included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month.
The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be recognized into earnings. Contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. However, as mentioned previously, the effective portion of the gains and losses for these contracts are not recognized in earnings until settlement at their then market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement for the effective portion of these hedges.
The fair value of our qualifying hedge positions at a point in time is not necessarily indicative of the value realized when such contracts settle.
Contract Value as of March 31, 2002
Maturity in
Maturity in Maturity in Maturity in 2005 and Total Fair
Sources of Fair Value 2002 2003 2004 Thereafter Value
(In millions)
Quoted market prices $ (15.9 ) $ (8.5 ) $ (1.0 ) $ — $ (25.4 )
Prices based on models or other valuation techniques (2.5 ) (1.3 ) (3.4 ) (4.1 ) (11.3 )
Total $ (18.4 ) $ (9.8 ) $ (4.4 ) $ (4.1 ) $ (36.7 )
Based upon the Company'sour 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)($25.0) million and $3.0$5.0 million, respectively. After considering the effectsaffects of commodity hedge positions in place at June 30, 2001,March 31, 2002, it is estimated that if NGL prices average $.01 per gallon less in the next twelve months, pre-tax net income would decrease $18.7approximately $15.8 million. Conversely, it isComparatively, the same sensitivity analysis as of March 31, 2001 estimated that if NGL prices average $.01 per
gallon more in the next twelve months pre-tax net income would increase $18.7decrease approximately $19.5 million. INTEREST RATE RISKThe hedge contracts are intended to mitigate the impact that price changes have on our physical positions.
19
Credit Risk
We sell NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of our NGL sales are made at market-based prices, including approximately 40% of NGL production that is committed to Phillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015. This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On all transactions where we are exposed to credit risk, we analyse the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. However, these transactions are generally subject to margin agreements with the majority of our counterparties.
Interest Rate Risk
We enter into debt arrangements that are exposed to market risks related to changes in interest rates. We periodically utilize interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical averages. As of June 30, 2001,March 31, 2002, the fair value of our interest rate swap was a liability of $7.4 million.
As of March 31, 2002, we had approximately $119.9$256.5 million outstanding under a commercial paper program and no outstanding bank borrowings.program. As a result, we are exposed to market risks related to changes in interest rates. In the future, we intend to manage our interest rate exposure using a mix of fixed and floating interest rate debt. An increase of .5% in interest rates would result in an increase in annual interest expense of approximately $0.6$2.5 million.

FOREIGN CURRENCY RISK
Foreign Currency Risk
Our primary foreign currency exchange rate exposure at June 30, 2001March 31, 2002 was the Canadian dollar. Foreign currency risk associated with this exposure was not material.

19
23

20
PART II. OTHER INFORMATION

ITEM
Item 1. LEGAL PROCEEDINGSLegal Proceedings
For information concerning litigation and other contingencies, see Part I. Item 1, Note 65 to the Consolidated Financial Statements, "Commitments“Commitments and Contingent Liabilities,"” of this report and Item 3, "Legal“Legal Proceedings,"” included in our Form 10-K for December 31, 2000,2001, 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 the consolidated results of operations or financial position.

ITEMposition of the Company.
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.

20
24

(a) Exhibits
10.01 364-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 29, 2002.
(b) Reports on Form 8-K
None.
21
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)

21
25

DUKE ENERGY FIELD SERVICES, LLC
May 15, 2002
/s/ Rose M. Robeson
Rose M. Robeson
Vice President and Chief Financial Officer
(On Behalf of the Registrant and as
Principal Financial and Accounting Officer)
22
EXHIBIT INDEX
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
29, 2002.


For Quarter Ended March 31, 2002		Commission File Number 0-31095


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


PART I. FINANCIAL INFORMATION ~~(UNAUDITED)~~
	Item 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
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED BALANCE SHEETS
		CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations.................. 12~~Operations
	Item 3. Quantitative and Qualitative Disclosure about Market ~~Risks............................................. 18~~ Risks
PART II. OTHER INFORMATION
	Item 1. Legal ~~Proceedings...................................................................................... 20~~Proceedings
	Item 6. Exhibits and Reports on Form ~~8-K....................................................................... 20 Signatures............................................................................................. 21~~ 8-K
SIGNATURES
364-Day Credit Agreement


Item						Page

					PART I. FINANCIAL INFORMATION (UNAUDITED)
	1.	Financial Statements					1
			Consolidated Statements of Operations for the Three Months Ended March 31, 2002 and 2001				1
			Consolidated Statements of Comprehensive (Loss) Income for the Three Months Ended March 31, 2002 and 2001				2
			Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2002 and 2001				3
			Consolidated Balance Sheets as of March 31, 2002 and December 31, 2001				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					16
				PART II. OTHER INFORMATION
	1.	Legal Proceedings					21
	6.	Exhibits and Reports on Form 8-K					21
		Signatures					22

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

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

	•		the level of creditworthiness of counterparties to transactions;

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

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

	•		weather and other natural phenomena;

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

	•		our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products; and

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


			THREE MONTHS ENDED,
			MARCH 31,

			2002			2001

OPERATING REVENUES:
	Sales of natural gas and petroleum products		$	1,175,524		$	2,381,883
	Sales of natural gas and petroleum products—affiliates			308,836			940,299
	Transportation, storage and processing			69,577			57,890

		Total operating revenues		1,553,937			3,380,072

COSTS AND EXPENSES:
	Purchases of natural gas and petroleum products			1,204,684			2,699,236
	Purchases of natural gas and petroleum products—affiliates			100,649			313,263
	Operating and maintenance			107,960			89,491
	Depreciation and amortization			73,759			66,856
	General and administrative			36,696			28,217
	General and administrative—affiliates			2,461			4,189
	Net loss (gain) on sale of assets			5,188			(868	)

		Total costs and expenses		1,531,397			3,200,384

OPERATING INCOME				22,540			179,688
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES				6,070			5,176
INTEREST EXPENSE				43,309			42,017

(LOSS) INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE				(14,699	)		142,847
INCOME TAX EXPENSE				2,301			58

(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE				(17,000	)		142,789
CUMULATIVE EFFECT OF ACCOUNTING CHANGE				—			(411	)

NET (LOSS) INCOME				(17,000	)		142,378
DIVIDENDS ON PREFERRED MEMBERS’ INTEREST				7,125			7,125

(DEFICIT) EARNINGS AVAILABLE FOR MEMBERS’ INTEREST			$	(24,125	)	$	135,253


					MARCH 31,			DECEMBER 31,
					2002			2001

				ASSETS
CURRENT ASSETS:
	Cash				$	3,332		$	4,906
	Accounts receivable:
		Customers, net				575,769			520,118
		Affiliates				36,265			230,521
		Other				107,941			136,810
	Inventories					72,272			82,935
	Unrealized gains on trading and hedging transactions					90,301			180,809
	Other					7,358			9,060

			Total current assets			893,238			1,165,159

PROPERTY, PLANT AND EQUIPMENT, NET						4,726,854			4,711,960
INVESTMENT IN AFFILIATES						138,315			132,252
INTANGIBLE ASSETS:
	Natural gas liquids sales and purchases contracts, net					91,010			94,019
	Goodwill, net					421,176			421,176

			Total intangible assets			512,186			515,195

UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS						14,051			19,095
OTHER NONCURRENT ASSETS						87,138			86,548

			TOTAL ASSETS		$	6,371,782		$	6,630,209

				LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable:
		Trade			$	492,895		$	620,094
		Affiliates				13,376			25,620
		Other				55,333			76,914
	Short term debt					256,535			212,955
	Unrealized losses on trading and hedging transactions					108,723			84,811
	Accrued interest payable					25,660			57,417
	Accrued taxes other than income					11,524			24,646
	Distributions payable to members					17,490			45,672
	Other					117,664			102,694

			Total current liabilities			1,099,200			1,250,823

DEFERRED INCOME TAXES						14,566			14,362
LONG TERM DEBT						2,232,876			2,235,034
UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS						41,820			25,188
OTHER LONG TERM LIABILITIES						13,883			15,845
MINORITY INTERESTS						135,989			135,915
PREFERRED MEMBERS’ INTEREST						300,000			300,000
COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS’ EQUITY:
	Members’ interest					1,709,290			1,709,290
	Retained earnings					854,091			895,707
	Accumulated other comprehensive (loss) income					(29,933	)		48,045

			Total members’ equity			2,533,448			2,653,042

TOTAL LIABILITIES AND MEMBERS’ EQUITY					$	6,371,782		$	6,630,209


		For The Three
		Months Ended
		March 31,

		2002			2001

		(In Thousands)
Reported net (loss) income		$	(17,000	)	$	142,378
Add: Goodwill amortization			—			1,492

	Adjusted net (loss) income	$	(17,000	)	$	143,870


		Balance		Acquired				Balance
		December 31, 2001		Goodwill		Other		March 31, 2002

Natural gas gathering, processing, transportation, marketing and storage		$	394,054	$	—	$	—	$	394,054
NGL fractionation, transportation, marketing and trading			27,122		—		—		27,122

	Total consolidated	$	421,176	$	—	$	—	$	421,176


			As Of

			March 31,		December 31,
			2002		2001

			(In Thousands)
Total assets:
	Natural gas		$	5,333,867	$	5,326,889
	NGLs			229,208		258,177
	Corporate (c)			808,707		1,045,143

		Total assets	$	6,371,782	$	6,630,209

(a)		Intersegment sales represent sales of NGLs from the natural gas ~~................................................... $ 1,211,835 $ 1,675,793 $ 3,955,248 $ 2,575,007~~segment to the 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 earningssegment at either index prices or weighted average prices of unconsolidated affiliates: Natural Gas ................................................... $ 10,458 $ 7,374 $ 16,122 $ 13,888 NGLs .......................................................... 446 574 (42) 819 ------------ ------------ ------------ ------------ Total equity in earningsNGLs. Both measures 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 intersegment sales are effectively based on current economic market conditions.

(b)		EBITDA ............................................ $ 224,158 $ 212,094 $ 475,878 $ 312,574 ============ ============ ============ ============ Depreciationconsists of income from continuing operations before interest expense, income tax expense, 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) ------------ ------------ ------------ ------------ Totalexpense. EBIT .............................................. $ 156,297 $ 144,829 $ 341,161 $ 207,215 ============ ============ ============ ============ Corporate interest expense ....................................... $ 40,375 $ 45,374 $ 82,392 $ 59,851 ============ ============ ============ ============ Income beforeis equal to 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 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 ============ ============ ============ ============


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

	•		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;

	•		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.


	(In millions)
Fair value of contracts outstanding at the beginning of the period	$	37.4
Contracts realized or otherwise settled during the period		(51.6	)
Net mark-to-market changes in fair values		4.7

Fair value of contracts outstanding at the end of the period	$	(9.5	)


		Fair Value of Contracts as of March 31, 2002

										Maturity in
		Maturity in		Maturity in			Maturity in			2005 and
Sources of Fair Value		2002		2003			2004			Thereafter			Total Fair Value

							(In millions)
Prices supported by quoted market prices and other external sources		$	4.7	$	(3.1	)	$	(0.4	)	$	(2.9	)	$	(1.7	)
Prices based on models and other valuation methods			0.2		(4.0	)		(4.2	)		0.2			(7.8	)

	Total	$	4.9	$	(7.1	)	$	(4.6	)	$	(2.7	)	$	(9.5	)


		Contract Value as of March 31, 2002

											Maturity in
		Maturity in			Maturity in			Maturity in			2005 and			Total Fair
Sources of Fair Value		2002			2003			2004			Thereafter			Value

								(In millions)
Quoted market prices		$	(15.9	)	$	(8.5	)	$	(1.0	)	$	—		$	(25.4	)
Prices based on models or other valuation techniques			(2.5	)		(1.3	)		(3.4	)		(4.1	)		(11.3	)

	Total	$	(18.4	)	$	(9.8	)	$	(4.4	)	$	(4.1	)	$	(36.7	)


(a)	Exhibits

	10.01	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 29, 2002.

(b)	Reports on Form 8-K

	None.


		DUKE ENERGY FIELD SERVICES, LLC

May 15, 2002

		/s/ Rose M. Robeson

		Rose M. Robeson Vice President and Chief Financial Officer (On Behalf of the Registrant and as Principal Financial and Accounting Officer)


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~~ 29, 2002.