1 ================================================================================UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549----------____________________
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d)15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934FOR QUARTER ENDED MARCH 31, 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 of incorporation) (IRS Employer Identification No.)
Delaware 76-0632293 (State or other jurisdiction of incorporation) (IRS Employer Identification No.) 370
17TH STREET, SUITE17th Street, Suite 900DENVER, 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 [ ]================================================================================2 DUKE ENERGY FIELD SERVICES, LLC FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2001 INDEXTABLE OF CONTENTSDUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2002INDEX
Item Page 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 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
4PART I. FINANCIAL INFORMATION
ITEMItem 1.
FINANCIAL STATEMENTSFinancial StatementsDUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OFINCOME (UNAUDITED) (IN THOUSANDS)OPERATIONS
THREE MONTHS ENDED, MARCH 31, ---------------------------- 2001 2000 ----------- -----------OPERATING REVENUES: Sales of natural gas and petroleum products ................ $ 2,381,883 $ 1,251,098 Sales of natural gas and petroleum products--affiliates .... 940,299 164,367 Transportation, storage and processing ..................... 57,890 35,073 Transportation, storage and processing--affiliates ......... -- 673 ----------- ----------- Total operating revenues ............................. 3,380,072 1,451,211 ----------- ----------- COSTS AND EXPENSES: Natural gas and petroleum products ......................... 2,699,236 1,252,769 Natural gas and petroleum products--affiliates .................................... 313,263 25,742 Operating and maintenance .................................. 89,491 49,039 Depreciation and amortization .............................. 66,856 38,094 General and administrative ................................. 28,217 19,811 General and administrative--affiliates ..................... 4,189 9,890 Net (gain) loss on sale of assets .......................... (868) 239 ----------- ----------- Total costs and expenses ............................. 3,200,384 1,395,584 ----------- ----------- OPERATING INCOME .............................................. 179,688 55,627 EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES .................................. 5,176 6,759 INTEREST EXPENSE: Interest expense (income) .................................. 42,017 (8) Interest expense--affiliates ............................... -- 14,485 ----------- ----------- Total interest expense ............................... 42,017 14,477 ----------- ----------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE ....................................... 142,847 47,909 INCOME TAX EXPENSE (BENEFIT) .................................. 58 (313,991) ----------- ----------- NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ..................................................... 142,789 361,900 CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX ............ 411 -- ----------- ----------- NET INCOME .................................................... 142,378 361,900 DIVIDENDS ON PREFERRED MEMBERS' INTEREST ...................... 7,125 -- ----------- ----------- EARNINGS AVAILABLE FOR MEMBERS' INTEREST ...................... $ 135,253 $ 361,900 =========== ===========
(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
5DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME(UNAUDITED) (IN THOUSANDS)
THREE MONTHS ENDED, MARCH 31, ------------------------ 2001 2000 --------- ---------NET INCOME ..................................................... $ 142,378 $ 361,900 OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Cumulative effect of change in accounting principle ......... 6,626 -- Foreign currency translation adjustment ..................... (912) (284) Net unrealized gains (losses) on cash flow hedges ........... (18,202) -- Reclassification adjustment ................................. 16,994 -- --------- --------- Total other comprehensive income (loss), net of tax .... 4,506 (284) --------- --------- TOTAL COMPREHENSIVE INCOME ..................................... $ 146,884 $ 361,616 ========= =========
(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
6DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS(UNAUDITED) (IN THOUSANDS)
THREE MONTHS ENDED, MARCH 31, ------------------------ 2001 2000 --------- ---------CASH FLOWS FROM OPERATING ACTIVITIES: Net income ..................................................................... $ 142,378 $ 361,900 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ............................................... 66,856 38,094 Deferred income taxes ....................................................... -- (308,230) Change in derivative fair value ............................................. (11,197) -- Equity in earnings of unconsolidated affiliates ............................. (5,176) (6,759) Loss (gain) on sale of assets ............................................... (868) 239 Change in operating assets and liabilities (net of effects of acquisitions) which provided (used) cash: Accounts receivable ......................................................... 89,884 96,427 Accounts receivable--affiliates ............................................. (97,851) (15,897) Inventories ................................................................. 46,695 (13,843) Unrealized loss (gain) on mark-to-market transactions ....................... 19,019 (65,876) Other current assets ........................................................ 1,836 114,328 Other noncurrent assets ..................................................... (11,057) 3,016 Accounts payable ............................................................ 108,781 (60,725) Accounts payable--affiliates ................................................ (10,170) 12,882 Accrued interest payable .................................................... (30,230) -- Unrealized losses on mark-to-market transactions ............................ (21,268) 58,809 Other current liabilities ................................................... (26,310) (10,132) Other long term liabilities ................................................. (5,589) (19,436) --------- --------- Net cash from operating activities ....................................... 255,733 184,797 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions and other capital expenditures .................................... (63,118) (129,591) Investment expenditures ........................................................ (1,114) (521) Investment distributions ....................................................... 16,024 5,662 Proceeds from sales of assets .................................................. 18,551 13,031 --------- --------- Net cash from investing activities ....................................... (29,657) (111,419) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Net decrease in advances--parents .............................................. (723) (73,998) Distributions to parents ....................................................... (127,561) -- Proceeds from issuing debt ..................................................... 250,000 -- Short term debt--net ........................................................... (346,410) -- --------- --------- Net cash from financing activities ....................................... (224,694) (73,998) --------- --------- NET CHANGE IN CASH AND CASH EQUIVALENTS ........................................... 1,382 (620) CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD .................................... 1,553 792 --------- --------- CASH AND CASH EQUIVALENTS, END OF PERIOD .......................................... $ 2,935 $ 172 ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Cash paid for interest (net of amounts capitalized) .............. $ 16,602 $ --
(Unaudited)
(In Thousands)
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.
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7DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED BALANCE SHEETS(UNAUDITED) (IN THOUSANDS)
MARCH 31, DECEMBER 31, 2001 2000 ----------- ------------ASSETS CURRENT ASSETS: Cash and cash equivalents ...................................................... $ 2,935 $ 1,553 Accounts receivable: Customers, net .............................................................. 597,221 725,379 Affiliates .................................................................. 351,128 253,277 Other ....................................................................... 105,954 67,316 Inventories .................................................................... 36,630 83,325 Unrealized gains on trading and hedging transactions ........................... 51,716 46,185 Other .......................................................................... 11,489 14,275 ----------- ----------- Total current assets ..................................................... 1,157,073 1,191,310 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT, NET ................................................ 4,153,723 4,152,480 INVESTMENT IN AFFILIATES .......................................................... 250,575 261,551 INTANGIBLE ASSETS: Natural gas liquids sales contracts, net ....................................... 95,479 97,956 Goodwill, net .................................................................. 374,703 376,195 ----------- ----------- Total intangible assets .................................................. 470,182 474,151 ----------- ----------- OTHER NONCURRENT ASSETS ........................................................... 87,365 90,606 ----------- ----------- TOTAL ASSETS ............................................................. $ 6,118,918 $ 6,170,098 =========== =========== LIABILITIES AND MEMBERS' EQUITY CURRENT LIABILITIES: Accounts payable: Trade ....................................................................... $ 1,010,024 $ 915,130 Affiliates .................................................................. 51,294 61,464 Other ....................................................................... 58,502 41,322 Short term debt ................................................................ -- 346,410 Unrealized losses on trading and hedging transactions .......................... 43,264 51,179 Accrued interest payable ....................................................... 19,411 49,641 Accrued taxes other than income ................................................ 13,794 21,717 Distributions payable to members ............................................... 2,126 127,561 Other .......................................................................... 98,283 114,408 ----------- ----------- Total current liabilities ................................................ 1,296,698 1,728,832 ----------- ----------- LONG TERM DEBT .................................................................... 1,936,884 1,688,157 OTHER LONG TERM LIABILITIES ....................................................... 26,866 32,274 PREFERRED MEMBERS' INTEREST ....................................................... 300,000 300,000 COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS' EQUITY: Members' interest .............................................................. 1,709,476 1,709,290 Retained earnings .............................................................. 846,917 713,974 Accumulated other comprehensive income (loss) .................................. 2,077 (2,429) ----------- ----------- Total members' equity ................................................... 2,558,470 2,420,835 ----------- ----------- TOTAL LIABILITIES AND MEMBERS' EQUITY ............................................. $ 6,118,918 $ 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.
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8DUKE ENERGY FIELD SERVICES, LLC
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
(Unaudited)1.
GENERALGeneralDuke Energy Field Services, LLC (with its consolidated subsidiaries,
"the Company"“the Company” or"Field“Field ServicesLLC"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 POLICIESAccounting PoliciesConsolidation
-—The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, afterthe 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 arerecognizedrecorded in the Consolidated Balance Sheets at their fair value as UnrealizedgainsGains orlossesUnrealized Losses ontradingTrading andhedging transactions, as appropriate.Hedging Transactions. On the datethe swap, futuresthat swaps or option contracts are entered into, the Company designates the derivative as either held for trading (trading instruments),; as a hedgeof the fair valueof a recognized asset,orliability orof an unrecognizedfirm 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
alsoformally assesses, both at thehedge'shedge contracts inception and on an ongoing basis, whether thederivatives 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 theextrinsictime 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 purposesfavorable or unfavorable price movementis reported as Purchases of NaturalgasGas andpetroleum products purchasesPetroleum Products in the Consolidated Statements ofIncome.Operations. An offsetting amount is recordedgrossin the Consolidated Balance Sheets as UnrealizedgainsGains orlossesUnrealized Losses ontradingTrading andhedging transactions.Hedging Transactions. When a contract to sellenergyis physically settled, the fair value entries are reversed and the gross amount invoiced to the customer is included as Sales ofnatural gasNatural Gas andpetroleum productsPetroleum Products in the Consolidated Statements ofIncome.Operations. Similarly, when a contract to purchaseenergyis physically settled, the purchase price is included as Purchases of NaturalgasGas andpetroleum products purchasesPetroleum Products in the Consolidated Statements ofIncome.Operations. If a contract is not physically settled, the unrealized gain or unrealized lossonin thebalance sheetConsolidated Balance5
Sheets is
reversed andreclassified to a receivable or payable account. For income statement purposes,the contract is treated as a purefinancialinstrument, so there issettlement has no net operating income presentation effect on the Consolidated Statements ofIncome. Fair ValueOperations.Commodity Cash Flow Hedges
- Changes— The effective portion of the change inthefair value of a derivativethat isdesignated andqualifiesqualified as afair valuecash flow hedge are included in the Consolidated Statements of Comprehensive (Loss) Income asSales of natural gas and petroleum products and Natural gas and petroleum products purchases, as appropriate. An offsetting amount is recorded gross in the Consolidated Balance Sheets as Unrealized gains or losses on trading and hedging transactions and the physical portion of a fair value hedge of a firm commitment is included in the Consolidated Balance Sheets as Accounts receivable - Customers, net or Accounts payable - Trade. Cash Flow Hedges - The fair value of a derivative that is designated and qualifies as a cash flow hedge is included in the Consolidated Balance Sheets as Unrealized gains or losses on trading and hedging transactions. The effective portion of the cash flow derivative is included inOthercomprehensive income (OCI)Comprehensive (Loss) Income (“OCI”) until earnings are affected by the hedged item.Hedge resultsSettlement amounts of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of59 IncomeOperations 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 derivativewill continueno longer qualifies as an effective hedge, the derivative continues to be carried on thebalance sheetConsolidated 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 areeffectedaffected by the hedged item, unless it is no longer probable that the hedged transaction willoccur. Under these circumstances,occur, in which case, the gains and losses that were accumulated in OCI will be immediately recognizedimmediatelyin current-period earnings.Cumulative EffectCommodity Fair Value Hedges — Changes in the fair value of
Changea derivative that is designated and qualifies as a fair value hedge are included inAccounting Principle -the Consolidated Statements of Operations as Sales of Natural Gas and Petroleum Products and Purchases of Natural Gas and Petroleum Products, as appropriate. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of Operations in the same accounts as the changes in the fair value of the derivative, with offsetting amounts in the Consolidated Balance Sheets as Other Current Assets, Other Noncurrent Assets, Other Current Liabilities, or Other Long Term Liabilities, as appropriate.Interest Rate Fair Value Hedges — The Company
adoptedenters into interest rate swaps to convert some of its fixed-rate long term debt to floating-rate long term debt. Hedged items in fair value hedges are marked to market with the respective derivative instruments. Accordingly, the Company’s hedged fixed-rate debt is carried at fair value. The terms of the outstanding swap match those of the associated debt which permits the assumption of no ineffectiveness, as defined by Statement of Financial Accounting Standards (“SFAS”) No. 133,(SFAS 133), "Accounting“Accounting for Derivative Instruments and HedgingActivities," on January 1, 2001. In accordance withActivities.” As such, for thetransition provisionslife ofSFAS 133,theCompany 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 three months ended March 31, 2001, the Company reclassified to earnings a $17.0 million loss from OCI for derivatives included in the transition adjustment for hedge transactions that occurred. Currently, there are ongoing discussions surrounding the implementation and interpretation of SFAS 133 by the Financial Accounting Standards Board's Derivative Implementation Group. If the definition of derivative instruments is altered, this may result in another transition adjustment and impact subsequent operating results.swap no ineffectiveness will be 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 on a go forward basis will consist primarily of miscellaneous state, local and foreign taxes.— 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. Thedistribution 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— The Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” 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 are subject to a fair-value-based annual impairment assessment. The Company did not recognize any impairments due to the implementation of SFAS No. 142. The standard also requires certain 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 adopted SFAS No. 144, “Accounting for the Impairment 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. 121, but significantly change the criteria for classifying an asset as held-for-sale. The impact of adopting SFAS No. 144 was not material to the 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 RISKDerivative Instruments, Hedging Activities and Credit RiskCommodity price risk
-— TheCompany'sCompany’s principal operations of gathering, processing, transportation and storage of natural gas, and the accompanying operations ofprocessing,fractionation, transportation, trading and marketing ofnatural gas liquidsNGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs and naturalgas 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 gasacquisitioncontracts enteredintoin 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 theCompany'sCompany’s subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and7
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 ofachieving profits throughrealizing a positive margin from the purchase andsalessale of commodity-based instruments.The trading of energy related products and services exposes the Company to the fluctuations in the market values of traded instruments.Corporate economic risks— The Company
manages its traded instrument portfolio with strict policies which limit 610 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 enterenters into debt arrangements thatmay have interest rate risk fromare exposed to market risks related to changes in interest rates. The Company periodicallyutilizesuses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. TheCompany'sCompany’s primary goals include (1) maintaining an appropriate ratio offixed ratefixed-rate debt to total debt for theCompany'sCompany’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historicalaverages. For the three months ended March 31, 2001, the Company's existing interest rate derivative instruments were not material to its results of operations, cash flows or financial position.rates.Counterparty risks
-— The Companyhassells 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 riskfrom its extension of credit for sales of energy products and services, and will havemay affect the Company’s overall credit riskwith its counterpartiesinterms of settlement risk and performance risk.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 thecounterparties'counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis.Fair-valueThe 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 Companyutilizes fair-valueuses 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'sCompany’s exposure to fixed price risk via swapping out the fixed price risk for a floating price position(NYMEX(New York Mercantile Exchange or index based).For the three months ended March 31,
2001,2002, theCompany's fair-value hedges were effective. As such, the Company did not recognize a gaingains orlosslosses representing the ineffective portion ofall fair-value hedges.the Company’s fair value hedges were not material. All components of eachderivative'sderivative’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 asfair-valuefair value hedge items and therefore, did not recognizeaan associated gain or loss.Cash-flow hedges -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
Company uses cash flow hedging,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, asspecificallydefined by SFAS133, to reduce133. As such, for thepotential 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 disruptionlife of theCompany'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-counterswapagreements 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, 2001, the Company recognized a net loss of $12.9 million of which a $4.1 million gain represented the totalno ineffectivenessof all cash-flow hedges and a $17.0 million loss represented the total derivative settlements. The extrinsic value of the options, $1.4 million for the period ended March 31, 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 hedge item is recorded.will be recognized. As of March 31,2001, $5.4 million2002, the fair value of thedeferred net gainsinterest rate swap of ($7.4) million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses onderivative instruments accumulatedTrading and Hedging Transactions with an offset to the underlying debt included inOCI are expected to be reclassified as earnings during the next twelve months as the hedge transactions occur.Long Term Debt.Commodity Derivatives — Trading— The
maximum term over whichtrading of energy related products and services exposes the Companyis hedgingto the fluctuations in the market values of traded instruments. The Company manages its traded instrument portfolio with strict policies which limit exposure tothe variabilitymarket risk and require daily reporting to management offuture cash-flows is 24 months. 711 Other - The Company periodically utilizes foreign-exchange contractspotential financial exposure. These policies include statistical risk tolerance limits using historical price movements tomanage currencycalculate a daily earnings at riskrelated to an anticipated acquisition. For the period ended March 31, 2001, the Company recognized a $0.9 million net loss in current-period earnings for the mark-to-market adjustment of foreign-exchange contracts.measurement.4.
FINANCINGFinancingCredit Facility with Financial Institutions
-—On March30, 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 March30, 2001.29, 2002. The New Facility is used to support theCompany'sCompany’s commercial paper program and for working capital and other general corporate purposes. The New Facility matures on March29, 2002,28, 2003, however, any outstanding loans under the New Facility at maturity may, at theCompany'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 theCompany'sCompany’s option and based on theCompany'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 March 31,2001,2002, there were no borrowings against the New Facility.On February 2, 2001,At March 31, 2002 the Company
issued $250had a $30.0 millioninoutstanding 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 theCompany. The Company usedunconsolidated subsidiary are pledged as collateral for theproceeds from the issuance of the notes to repay short termdebt.5.
COMMITMENTS AND CONTINGENT LIABILITIESCommitments and Contingent LiabilitiesLitigation
-— The midstream natural gas industry has seenan increase in thea 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.ManyA number of these cases are now being brought as class actions. The Company and its subsidiaries are currently named as defendants incertainsome of these9
cases. Management believes the Company and its subsidiaries have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend.
A judgement has been entered in the case of Chevron U.S.A., Inc. versus GPM Gas Corporation (GPM), a wholly owned subsidiary of Field Services LLC, upholding and construing most favored nations clauses in three 1961 West Texas gas purchase contracts. Although a U.S. District Court for the Western District of Texas, Midland Division decided in September 1999 that GPM owes Chevron damages in the amount of $13.8 million through July 31, 1998, plus 6% interest from that date and attorneys' fees in the amount of $0.3 million, GPM has appealed the judgement to the U.S. Court of Appeals for the Fifth Circuit.Management believes that the final
depositiondisposition of these proceedings will not have a material adverse effect on the consolidated results of operationscash flowsor financial position of the Company.Environmental - On June 17, 1999, the EPA published in the Federal Register a final Maximum Available Control Technology ("MACT") standard under Section 112 of the Clean Air Act to limit emissions of Hazardous Air Pollutants ("HAPs") from oil and natural gas production as well as from natural gas transmission and storage facilities. The MACT standard requires that affected facilities reduce their emissions of HAPs by 95%, and this will affect the Company's various large dehydration units and potentially some of the Company's storage vessels. This new standard will require that the Company achieve this reduction by either process modifications or installing new emissions control technology. The MACT standard will affect the Company and its competitors in varying degrees. The rule allows most affected sources until at least June 2002 to comply with the requirements. While additional capital costs are likely to result from this rule or other potential air regulations, management believes that these changes will not have a material adverse effect on the Company's business, financial position or results of operations. 812 The Company has various ongoing remedial matters related to historical operations similar to others in the industry, based primarily on state authorities generally described above. These are typically managed in conjunction with the relevant state or federal agencies to address specific conditions, and in some cases are the responsibility of other entities based upon contractual obligations related to the assets. On March 31, 1999, the Company acquired the midstream natural gas gathering and processing assets of Union Pacific Resources located in several states, which include 18 natural gas plants and 365 gathering facility sites. In connection with pre-April 1999 soil and ground water conditions identified as part of this transaction, the Company has entered into an agreement with a third party environmental/insurance partnership for a one-time premium payment subject to certain deductibles. With respect to these identified environmental conditions, the environmental partner has assumed liability and management responsibility for environmental remediation, and the insurance partner is providing financial management, program oversight, remediation cost cap insurance coverage for a 30 year term, and pollution legal liability coverage for a 20 year term. While the Company could face liability in the event of default, management believes this innovative approach can promote pro-active site cleanup and closure, reduce internal resource needs for managing remediation, and may improve the marketability of assets based on transferability of this insurance coverage. Also, in August 1996, the Company acquired certain gas gathering and processing assets in three states from Mobil Corporation. Under the terms of the asset purchase agreement, Mobil has retained the liabilities and costs related to various pre-August 1996 environmental conditions that were identified with respect to those assets. Mobil has formulated or is in the process of developing plans to address certain of these conditions, which the Company will review and monitor as clean-up activities proceed. The Company is presently resolving 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 115 of the Company's facilities that did not meet specific administrative filing deadlines for required air permit paperwork. In addition, at this time the Company is actively resolving 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. Management believes that these apparent non-compliance issues being addressed with the Texas and New Mexico agencies under relevant air programs will result in total penalty assessments of less than $500,000. The Company has been in discussions with the Colorado Air Pollution Control Division regarding various asserted non-compliance issues arising from agency inspections of our Colorado facilities in 2000 and 1999, and arising from compliance issues disclosed to the agency pursuant to permit requirements or voluntarily disclosed to the agency in 2000. These items relate to various specific and detailed terms of the Title V Operating Permits at seven gas plants and two compressor stations in Colorado, including, for example, record keeping requirements, parametric monitoring requirements, delayed filings, and operations inconsistent with throughput limits on particular pieces of equipment. As a result of these discussions, the Company received from the agency in March 2001 a comprehensive proposed settlement agreement to resolve all of these various items related to air permit compliance at the nine facilities. Although the Company is still discussing the appropriate resolution of these apparent instances of non-compliance with the Division, management believes that the comprehensive resolution for all nine facilities will result in a total penalty assessment of less than $575,000.6.
BUSINESS SEGMENTSBusiness SegmentsThe 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 and913services, 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 measuresutilizedused 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.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 10
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 MONTHS ENDED MARCH 31, ---------------------------- 2001 2000 ----------- ----------- (IN THOUSANDS)Operating revenues: Natural(a) Intersegment sales represent sales of NGLs from the natural gas .................................................... $ 2,743,413 $ 899,214segment to the NGLs........................................................... 1,227,830 798,816 Intersegment(a) ................................................ (591,171) (246,819) ----------- ----------- Total operating revenues ................................. $ 3,380,072 $ 1,451,211 =========== =========== Margin: Natural gas .................................................... $ 355,757 $ 147,856 NGLs ........................................................... 11,816 24,844 ----------- ----------- Total margin ............................................. $ 367,573 $ 172,700 =========== =========== Other operating costs: Natural gas .................................................... $ 88,237 $ 48,729 NGLs ........................................................... 386 549 Corporate ...................................................... 32,406 29,701 ----------- ----------- Total other operating costs .............................. $ 121,029 $ 78,979 =========== =========== Equity in earningssegment at either index prices or weighted average prices ofunconsolidated affiliates: Natural Gas .................................................... $ 4,688 $ 6,514 NGLs ........................................................... 488 245 ----------- ----------- Total equity in earningsNGLs. Both measures ofunconsolidated affiliates .... $ 5,176 $ 6,759 =========== =========== EBITDA(b): Natural gas .................................................... $ 272,208 $ 105,641 NGLs ........................................................... 11,918 24,540 Corporate ...................................................... (32,406) (29,701) ----------- ----------- Totalintersegment sales are effectively based on current economic market conditions.(b) EBITDA ............................................. $ 251,720 $ 100,480 =========== =========== Depreciationconsists of income from continuing operations before interest expense, income tax expense, andamortization: Natural gas .................................................... $ 63,481 $ 34,225 NGLs ........................................................... 2,295 3,027 Corporate ...................................................... 1,080 842 ----------- ----------- Totaldepreciation and amortization...................... $ 66,856 $ 38,094 =========== ===========1014
FOR THE THREE MONTHS ENDED MARCH 31, ------------------------ 2001 2000 --------- --------- (IN THOUSANDS)EBIT(b): Natural gas ............................... $ 208,727 $ 71,416 NGLs ...................................... 9,623 21,513 Corporate ................................. (33,486) (30,543) --------- --------- Totalexpense. EBIT.......................... $ 184,864 $ 62,386 ========= ========= Corporate interest expense ................... $ 42,017 $ 14,477 ========= ========= 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 incometaxes: Natural gas ............................... $ 208,727 $ 71,416 NGLs ...................................... 9,623 21,513 Corporate ................................. (75,503) (45,020) --------- --------- Total income before income taxes .... $ 142,847 $ 47,909 ========= ========= Capital Expenditures: Natural gas ............................... $ 60,885 $ 121,795 NGLs ...................................... 540 5,762 Corporate ................................. 1,693 2,034 --------- --------- Totalor 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 capitalexpenditures .......... $ 63,118 $ 129,591 ========= =========expenditures. However, not all EBITDA or EBIT may be available to service debt.(c) Includes items such as unallocated working capital, intercompany accounts and other assets.
AS OF -------------------------- MARCH 31, DECEMBER 31, 2001 2000 ---------- ------------ (IN THOUSANDS)Total assets: Natural gas ............................... $4,808,539 $4,896,542 NGLs ...................................... 220,949 219,282 Corporate(c) .............................. 1,089,430 1,054,274 ---------- ---------- Total assets ........................ $6,118,918 $6,170,098 ========== ==========(a) Intersegment sales represent sales of NGLs from7. 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 ameasurement 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 toservice debt andissue securities tofund capital expenditures. However, not all EBITDA or EBIT may be available to service debt. (c) Includes items such as unallocated working capital, intercompany accounts and other assets. 1115 7. PRO FORMA DISCLOSURES$500.0 million. TheCompany holds the combined North American midstream natural gas gathering, processing, marketing and natural gas liquids businesses of Duke Energy and Phillips. The Combination occurred March 31, 2000 and was accounted for as a purchase. Phillips' revenues and expenses have not been included in the first quarter of 2000. Revenuesshelf registration statement provides for theperiod ended March 31, 2000, on a pro forma basis would have increased $542.4 million,issuance of senior notes, subordinated notes andnet income for the period ended March 31, 2000 would have increased by $65.7 million, if the Combination had occurred on January 1, 2000. 8. SUBSEQUENT EVENTS On May 1, 2001, the Company completed the acquisitiontrust preferred securities.11
Item 2. Management’s Discussion and Analysis of
the outstanding sharesFinancial Condition and Results ofCanadian Midstream Services, Ltd. (CMSL). In the transaction, the Company acquired all the outstanding shares and assumed the debt for approximately $161.0 million. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSOperationsThe following discussion details the material factors that affected our historical financial condition and results of operations during the three months ended March 31,
20012002 and2000.2001. 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. 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. OVERVIEWOverview
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
1216other 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 DuringEffects of Commodity Prices
The Company is exposed to commodity prices as a result of being paid for certain services in the
three months ended March 31, 2001,form of commodities rather than cash. For gathering services, theweighted average NGL price (based on index pricesCompany receives fees from producers to bring natural gas from theMont 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 andConway 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 andlocation mix) was approximately $0.60 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 pricesdeparted from this trendincreased sharply as major crude oil exporting countries agreed to maintain crude oil production at predetermined levels andfollowedworld demand for crude oil and NGLs increased. The lower crude oil and natural gas prices in 1998 and early 1999 caused a significant12
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 priceswillremained 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 ofnear-termnear term natural gas prices.PriceThe price increases in crude oil, NGLs and natural gashave 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 Americahasincreased by approximately38%19% fromapproximately 1,1641,263 inMarch2000 toapproximately 1,6091,497 inMarch2001.ThisThe decline in commodity prices over the final two quarters of 2001 and first quarter of 2002 negatively effected drilling activityincrease 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 apositivenegative effect on natural gas volumes gathered andprocessedprocessed.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. RESULTS OF OPERATIONSfirst quarter of 2001 relates to hedges placed during periods of increasing prices. Thefollowingslight gain recognized in the first quarter of 2002 is the result of hedging gains achieved as adiscussionresult ofour historical resultsa sharp decline in commodity prices during the third and fourth quarters ofoperations. The discussion for periods ending on or prior to2001 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 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 MARCH2002 compared with three months ended March 31, 2001COMPARED WITH THREE MONTHS ENDED MARCH 31, 2000 Operating Revenues. Operating revenues increased $1,928.9Gross Margin.Gross Margin decreased $118.0 million, or
133%,32% from$1,451.2$372.7 millionto $3,380.1 million. Operating revenues from the sale of natural gas and petroleum products accounted for $3,322.2 million of the total and $1,906.7 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 operationsin theCombination on March 31, 2000. NGL production during the 2001first quarterincreased 139,900 barrelsof 2001 to $254.7 million in 2002. This decrease was primarily the result of lower NGL prices of approximately $165.0 million (net of hedging) due to a $.29 perday, or 61%, from 231,200 barrels per daygallon decrease in2000 to 371,100 barrels per day in 2001. The primary cause of this increase was the addition of Phillips' midstream natural gas business,average NGL prices. These decreases were partially offset byreduced recoveries at certain facilities resulting from tightened fractionation spreads driven by high natural gas prices. Commodity prices also contributedapproximately $36.0 million due tohigher revenues. Weighted average NGL prices, based on our component product mix, were approximately $.10 per gallon higher and natural gas prices were approximately $4.57a $4.77 per million British thermalunits (Btus) higher for the first quarter of 2001.unit (“Btu”) decrease in natural gas prices. These priceincreaseschanges 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 Btusrespectively, as compared with $.50 per gallon and $2.52 per million Btus forduring thefirst quarter of 2000. Revenuessame 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
processing fees and other increased $22.1segment decreased $122.2 million, or62%34%, from$35.8$360.4 million to$57.9$238.2 million, mainly as a result of theCombination. A $14.6lower NGL prices. Commodity sensitive processing arrangements accounted for approximately $130.0 millionhedging loss(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
partially offset operating revenue increases. See "--Quantitative and Qualitative Disclosure About Market Risks." Costs and Expenses. Coststo $108.0 million in the same period ofnatural gas and petroleum products increased $1,734.0 million, or 136%, from $1,278.5 million to $3,012.5 million.2002. This increasewas due tois primarily theadditionresult ofthe Phillips' midstream natural gasacquisitions and expanded businessin the Combination (approximately $881.4) and the interaction of our natural gas and NGL purchase contracts with higher commodity prices. 1317 Operating and maintenance expenses increased $40.5 million, or 82%, from $49.0 million to $89.5 million. Of this increase, approximately $35.6 million was related to the addition of the Phillips' midstream natural gas business.activity. General and administrative expenses increased$2.7$6.8 million, or9%21%, from$29.7$32.4 million in the first quarter of 2001 to$32.4 million.$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
increased activity resulting from the addition of the Phillips' midstream natural gas business in the Combination offset by decreased centralized service charges from our parents. Depreciation and amortization increased $28.8 million, or 76%, from $38.1 million to $66.9 million. Of this increase, $21.8 million was due to the addition of the Phillips' midstream natural gas business in the Combination. The remainder was due to ongoing capital expenditures for well connections, facility maintenance/enhancements and acquisitions. Equity Earnings. Equity earnings of unconsolidated affiliates decreased $1.6 million, or 24%, from $6.8 million to $5.2 million. This decrease was due to 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. These decreases werehigher outstanding debt levels, partially offset bythe acquisition of the general partnershiplower interestin TEPPCO as of March 31, 2000. Interest. Interest expense increased $27.5 million, or 190%, from $14.5 million to $42.0 million. This increase was primarily the result of issuance of commercial paper and the subsequent third quarter 2000 and first quarter 2001 debt offerings.rates.Income Taxes.
At March 31, 2000, the PredecessorThe Companyconverted 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 deferred tax liability of $327.0 million was eliminated and a correspondingFirst quarter 2002 income taxbenefit was recorded. Ongoing tax expenses relate to various state, local and foreignexpense of $2.3 million is mainly the result of other miscellaneous taxesthat are not significant.associated tax-paying subsidiaries.Net Income.Net income decreased
$219.5$159.4 million from$361.9$142.4 million in the first quarter of 2001 to$142.4 million.a loss of $17.0 million in the first quarter of 2002. This decrease was largely the result ofthe elimination of the predecessor Company's net deferred tax liability of $327.0decreased NGL prices and14
increases in operating and general administrative expenses, slightly offset by lower natural gas prices and acquisition activity.
Liquidity and Capital Resources
Operating Cash Flows
Net cash provided by operating activity decreased $158.2 million in
2000, offset by a $107.5 million increase resultingthe first quarter of 2002 from theadditionfirst quarter 2001. The decrease is primarily due to a reduction in net income ofthe Phillips' midstream$159.4 million. The reduction in net income is largely due to significantly lower NGL prices.Price volatility in crude oil, NGLs and natural gas
businessprices have a direct impact on our use and generation of cash from operations.Investing Cash Flows
Our capital expenditures consist of expenditures for acquisitions and construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the
Combination, increasedperiod ended March 31, 2002, we spent approximately $106.8 million on capital expenditures. These capital expenditures were primarily for plant expansions, well connections and plant upgrades.Our level of capital expenditures for acquisitions and construction depends on many factors, including industry conditions, the availability of attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from operations and borrowings available under our commercial paper program, our credit facilities or other
acquisitions. EBITDA.available sources of financing.Financing Cash Flows
Bank Financing and Commercial Paper
In
addition to the generally accepted accounting principles (GAAP) measures described above, we also use the non-GAAP measure of EBITDA. EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBITDA is a measure used to provide information regarding our ability to cover fixed charges such as interest, taxes, dividends and capital expenditures. In addition, EBITDA provides a comparable measure to evaluate our performance relative to that of our competitors by eliminating the capitalization structure and depreciation charges, which may vary significantly within our industry. Although the GAAP financial statement measure of net income or loss, in total and by segment, is indicative of our profitability, net income does not necessarily reflect our ability to fund our fixed charges on a periodic basis. We therefore use GAAP and non-GAAP measures in evaluating our overall performance as well as that of our related segments. In addition, we use both types of measures to evaluate our performance relative to other companies within our industry. EBITDA for the natural gas gathering, processing, transportation and storage segment increased $166.6 million from $105.6 million to $272.2 million. Of this increase, approximately $152.3 million was due to the addition of the Phillips' midstream natural gas business in the Combination, and approximately $37.5 million was due to a $.10 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 ofMarch31, 2000. These benefits were offset by increased general and administrative costs associated with the Combination and approximately $57.7 million due to a $4.57 per million Btu increase in natural gas prices. 1418 EBITDA for the NGL's fractionation, transportation, marketing and trading segment decreased $12.6 million from $24.5 million in 2000 to $11.9 million in 2001 due primarily to lower margins associated with NGL trading and the disposition of two NGL pipelines effective January 1, 2001. LIQUIDITY AND CAPITAL RESOURCES CREDIT FACILITY WITH FINANCIAL INSTITUTIONS On March 30, 2001,2002, we entered into anew$650.0 million credit facility(the "New Facility"). The New Facility replaces(“thecredit facility that matured on March 30, 2001.Facility”), of which $150.0 million can be used for letters of credit. TheNewFacility is used to supportthe Company'sour commercial paper program and for working capital and other general corporate purposes. TheNewFacility matures on March29, 2002,28, 2003, however, any outstanding loans under theNewFacility at maturity may, atthe Company'sour option, be converted to a one-year term loan. TheNew Facility is a $675.0 million revolving credit facility, of which $150.0 million can be used for letters of credit. The NewFacility requiresthe Companyus to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. TheNewFacility bears interest at a rate equal to, atthe 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 March 31,2001,2002, there were no borrowings against theNewFacility.On February 2, 2001, the Company issued $250At 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 ofthesenior 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 consistContractual 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 otherfacilitiescontractual commitments to extend guarantees of credit andinfrastructure in additionother assistance towell connectionsvarious subsidiaries, investees andrefurbishmentother 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 ourexisting facilities. Forcontingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or thethree months endedoccurrence of certain future events. We would record a reserve if events occurred that required that one be established.At March 31,
2001,2002 wespentwere the guarantor of approximately$63.1$25.6 millionon capital expenditures. On May 1, 2001, the Company completed the acquisitionof debt associated with an unconsolidated subsidiary. Assets of theoutstanding shares of Canadian Midstream Services, Ltd. (CMSL). In the transaction, the Company acquired all the outstanding shares and assumed the debt for approximately $161.0 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. 1519 CASH FLOWS Net cash from operating activitiesunconsolidated subsidiary are pledged as collateral for thethree months ended March 31, 2001 improved to $255.7 million, from net cash from operating activities of $184.8 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 $29.7 million for the three months ended March 31, 2001 compared to $111.4 million for the same period in 2000. Acquisition of the ConocoQualitative Disclosure about Market RisksRisk and
Mitchell Energy assets in 2000 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 $224.7 million for the three months ended March 31, 2001 compared to $74.0 million for the same period in 2000. Tax related distributions to parents and repayment of the Company's remaining short term debt were the primary uses of this cash, offset by issuance of $250 million of 6 7/8% Senior Unsecured Notes due 2011 in February 2001. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKSAccounting PoliciesWe are exposed to market risks associated with commodity prices, credit exposure, interest rates
commodity prices,andequity 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 overallapprovalmanagement 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
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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 theCompany's marketingprice of NGLs andtrading operations, corporate hedging operations, mid-office function, and back office control group on commodity price risks and energy marketing and trading operations. The Company's treasury department manages the Company's credit risks. There have been no material changes in the Company's market risk since December 31, 2000. COMMODITY PRICE RISK We are subject to significant risks due to fluctuations in commodity prices, primarily with respect to the prices of 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
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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 affects of commodity hedge positions in place at March 31,2001,2002, it is estimated that if NGL prices average $.01 per gallon less in the next twelve months, pre-tax net income would decrease$19.5approximately $15.8 million.Conversely, it isComparatively, the same sensitivity analysis as of March 31, 2001 estimated thatif NGL prices average $.01 per gallon more in the next twelve monthspre-tax net income wouldincreasedecrease 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 March 31,
2001,2002, the fair value of our interest rate swap was a liability of $7.4 million.As of March 31, 2002, we had
noapproximately $256.5 million outstanding under a commercial paperor bank borrowings.program. As a result, we arenotexposed 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.FOREIGN CURRENCY RISKAn increase of .5% in interest rates would result in an increase in annual interest expense of approximately $2.5 million.Foreign Currency Risk
Our primary foreign currency exchange rate exposure at March 31,
20012002 was the Canadian dollar. Foreign currency risk associated with this exposure was not material.1620
PART II. OTHER INFORMATION
ITEMItem 1.
LEGAL PROCEEDINGSLegal ProceedingsFor information concerning litigation and other contingencies, see Part I. Item 1, Note 5 to the Consolidated Financial Statements,
"Commitments“Commitments and Contingent Liabilities,"” of this report and Item 3, “Legal Proceedings,” included in our Form 10-K for December 31, 2001, whichisare 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)Exhibits10.1 Second Amendment to Employment Agreement dated March 15, 2001 between Duke Energy Field Services, LPandMichael J. Panatier. (b) A current reportReports on Form 8-Kwas filed on February 1, 2001 and contained disclosure under Item 5, Other Events and under Item 7, Financial Statements and Disclosures. 17
(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 May 14, 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) 18
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 Second Amendment to Employment Agreement dated March 15, 2001 between364-Day Credit Facility among Duke Energy Field Services, LPLLC, Duke Energy Field Services Corporation, Bank of America, N.A., as Agent andMichael J. Panatier.the Lenders named therein, dated March 29, 2002.