SECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended June 30, | Commission File Number 0-31095 |
DUKE ENERGY FIELD SERVICES, LLC
Delaware | 76-0632293 | |
(State or other jurisdiction of incorporation) | (IRS Employer Identification No.) |
370 17th Street, Suite 9002500
Denver, Colorado 80202
(Address of principal executive offices)
(Zip Code)
303-595-3331
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yesx Noo
Indicate by check mark whether the registrant is an accelerated filer as defined by Rule 12b-2 of the Act. Yeso Nox
DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 20032004
INDEX
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words.
All of such statements other thanthat are not 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:
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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. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
DUKE ENERGY FIELD SERVICES, LLC(in thousands) Three Months Ended, Six Months Ended, June 30, June 30 2003 2002 2003 2002 OPERATING REVENUES: Sales of natural gas and petroleum products $ 1,230,955 $ 670,206 $ 2,674,069 $ 1,278,630 Sales of natural gas and petroleum products—affiliates 578,009 564,229 1,502,393 973,969 Transportation, storage and processing 67,406 62,978 127,931 120,274 Trading and marketing net margin 1,403 3,519 (32,791 ) 10,828 Total operating revenues 1,877,773 1,300,932 4,271,602 2,383,701 COSTS AND EXPENSES: Purchases of natural gas and petroleum products 1,371,225 937,832 3,261,917 1,696,986 Purchases of natural gas and petroleum products—affiliates 191,394 130,167 392,745 210,659 Operating and maintenance 114,584 105,695 220,959 210,362 Depreciation and amortization 76,268 69,160 152,078 140,587 General and administrative 34,696 33,361 71,414 70,059 General and administrative—affiliates 5,632 5,752 8,344 8,211 Other (60 ) 1,907 (158 ) 7,095 Total costs and expenses 1,793,739 1,283,874 4,107,299 2,343,959 OPERATING INCOME 84,034 17,058 164,303 39,742 EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES 11,816 7,836 23,870 13,906 INTEREST EXPENSE, NET 41,759 42,295 84,497 85,604 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 54,091 (17,401 ) 103,676 (31,956 ) INCOME TAX EXPENSE 281 3,313 2,052 5,614 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 53,810 (20,714 ) 101,624 (37,570 ) GAIN (LOSS) FROM DISCONTINUED OPERATIONS 28,709 (630 ) 32,357 (774 ) CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES — — (22,802 ) — NET INCOME (LOSS) 82,519 (21,344 ) 111,179 (38,344 ) DIVIDENDS ON PREFERRED MEMBERS’ INTEREST 4,750 7,125 9,500 14,250 EARNINGS (DEFICIT) AVAILABLE FOR MEMBERS’ INTEREST $ 77,769 $ (28,469 ) $ 101,679 $ (52,594 ) Three Months Ended Six Months Ended June 30, June 30, 2004 2003 2004 2003 Operating Revenues: Sales of natural gas and petroleum products $ 1,759 $ 1,409 $ 3,480 $ 3,025 Sales of natural gas and petroleum products to affiliates 545 578 1,156 1,502 Transportation, storage and processing 76 68 144 129 Trading and marketing net margin 2 1 4 (33 )
Total operating revenues 2,382 2,056 4,784 4,623
Costs and Expenses: Purchases of natural gas and petroleum products 1,863 1,555 3,752 3,624 Purchases of natural gas and petroleum products from affiliates 139 191 287 393 Operating and maintenance 107 113 201 218 Depreciation and amortization 75 75 150 150 General and administrative 41 41 82 79
Total costs and expenses 2,225 1,975 4,472 4,464
Operating Income 157 81 312 159 Equity in earnings of unconsolidated affiliates 14 12 31 24 Interest expense, net 39 42 79 84
Income from continuing operations before income taxes 132 51 264 99 Income tax expense 2 — 5 2
Income from continuing operations before cumulative effect of accounting change 130 51 259 97 Income from discontinued operations — 31 5 37 Cumulative effect of change in accounting principles — — — (23 )
Net income 130 82 264 111 Dividends on preferred members’ interest — 4 — 9
Earnings available for members’ interest $ 130 $ 78 $ 264 $ 102
See Condensed Notes to Consolidated Financial Statements.
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DUKE ENERGY FIELD SERVICES, LLC (LOSS)(in thousands) Three Months Ended, Six Months Ended, June 30, June 30, 2003 2002 2003 2002 NET INCOME (LOSS) $ 82,519 $ (21,344 ) $ 111,179 $ (38,344 ) OTHER COMPREHENSIVE INCOME (LOSS): Foreign currency translation adjustment 24,931 13,451 45,059 11,107 Net unrealized losses on cash flow hedges (24,858 ) (4,339 ) (61,241 ) (61,439 ) Reclassification of (gains) losses from cash flow hedges into earnings 24,542 2,542 66,226 (15,992 ) Total other comprehensive income (loss) 24,615 11,654 50,044 (66,324 ) TOTAL COMPREHENSIVE INCOME (LOSS) $ 107,134 $ (9,690 ) $ 161,223 $ (104,668 ) Three Months Ended Six Months Ended June 30, June 30, 2004 2003 2004 2003 Net income $ 130 $ 82 $ 264 $ 111 Other comprehensive income: Foreign currency translation adjustment (9 ) 25 (13 ) 45 Net unrealized losses on cash flow hedges (12 ) (24 ) (29 ) (61 ) Reclassification of previously deferred losses on cash flow hedges into earnings 24 24 42 66
Total other comprehensive income 3 25 — 50
Total comprehensive income $ 133 $ 107 $ 264 $ 161
See Condensed Notes to Consolidated Financial Statements.
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DUKE ENERGY FIELD SERVICES, LLCSTATEMENTS OF CASH FLOWS
BALANCE SHEETS(in thousands) Six Months Ended, June 30, 2003 2002 CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 111,179 $ (38,344 ) Adjustments to reconcile net income (loss) to net cash provided by operating activities: (Gain) loss on discontinued operations (32,357 ) 774 Cumulative effect of changes in accounting principles 22,802 — Depreciation and amortization 152,078 140,587 Deferred income tax benefit (29 ) (710 ) Equity in earnings of unconsolidated affiliates (23,870 ) (13,906 ) Other, net 10,174 6,221 Change in operating assets and liabilities which provided (used) cash: Accounts receivable (195,252 ) 13,441 Accounts receivable—affiliates 128,009 114,121 Inventories 23,336 (11,784 ) Net unrealized loss (gain) on mark-to-market and hedging transactions (32,467 ) 46,103 Other current assets (17,954 ) 4,313 Other noncurrent assets (3,300 ) (1,105 ) Accounts payable 98,993 (43,712 ) Accounts payable—affiliates (64,458 ) (10,737 ) Accrued interest payable 343 (2,890 ) Other current liabilities 13,796 15,397 Other long term liabilities (260 ) 9,256 Net cash provided by continuing operations 190,763 227,025 Net cash provided by discontinued operations 8,619 3,684 Net cash provided by operating activities 199,382 230,709 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (67,650 ) (165,203 ) Investment expenditures, net of cash acquired (512 ) 7,620 Investment distributions 31,058 24,040 Contributions to minority interests, net (538 ) — Proceeds from sales of discontinued operations 90,173 — Proceeds from sales of assets 5,484 — Net cash provided by (used in) continuing operations 58,015 (133,543 ) Net cash used in discontinued operations (2,946 ) (1,190 ) Net cash provided by (used in) investing activities 55,069 (134,733 ) CASH FLOWS FROM FINANCING ACTIVITIES: Distributions to members — (63,162 ) Short term debt, net (115,104 ) (23,930 ) Payment of debt (359 ) (152 ) Payment of dividends (9,500 ) (14,250 ) Net cash used in continuing operations (124,963 ) (101,494 ) Net cash used in discontinued operations — — Net cash used in financing activities (124,963 ) (101,494 ) EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH (1,225 ) 2,007 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 128,263 (3,511 ) CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 24,783 4,906 CASH AND CASH EQUIVALENTS, END OF PERIOD $ 153,046 $ 1,395 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION – Cash paid for interest (net of amounts capitalized) $ 82,164 $ 84,402 June 30, December 31, 2004 2003 Current assets: Cash and cash equivalents $ 253 $ 43 Accounts receivable: Customers, net of allowance for doubtful accounts of $4 and $8, respectively 961 872 Affiliates 49 57 Other 27 29 Inventories 46 45 Unrealized gains on mark-to-market and hedging transactions. 125 135 Other current assets 12 20
Total current assets 1,473 1,201
Property, plant and equipment, net 4,457 4,462 Investment in unconsolidated affiliates 186 190 Intangible assets: Commodity sales and purchases contracts, net 75 80 Goodwill, net 445 447
Total intangible assets 520 527
Unrealized gains on mark-to-market and hedging transactions 40 25 Other noncurrent assets 40 109
Total assets $ 6,716 $ 6,514
Current liabilities: Accounts payable: Trade $ 963 $ 857 Affiliates 22 16 Other 36 33 Short term debt 6 6 Accrued interest payable 59 59 Unrealized losses on mark-to-market and hedging transactions 124 153 Other current liabilities 128 150
Total current liabilities 1,338 1,274
Deferred income taxes 18 17 Long term debt 2,248 2,262 Unrealized losses on mark-to-market and hedging transactions 43 24 Other long term liabilities 89 73 Minority interests 125 120 Commitments and contingent liabilities Members’ equity: Members’ interest 1,709 1,709 Retained earnings 1,122 1,011 Accumulated other comprehensive income 24 24
Total members’ equity 2,855 2,744
Total liabilities and members’ equity $ 6,716 $ 6,514
See Condensed Notes to Consolidated Financial Statements.
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DUKE ENERGY FIELD SERVICES, LLCBALANCE SHEETS
STATEMENTS OF CASH FLOWS(in thousands) June 30, December 31, 2003 2002 CURRENT ASSETS: Cash and cash equivalents $ 153,046 $ 24,783 Accounts receivable: Customers, net 802,131 599,116 Affiliates 58,568 186,577 Other 43,613 50,466 Inventories 57,847 86,559 Unrealized gains on mark-to-market and hedging transactions 157,942 158,891 Other 24,033 6,713 Total current assets 1,297,180 1,113,105 PROPERTY, PLANT AND EQUIPMENT, NET 4,540,213 4,642,204 INVESTMENT IN AFFILIATES 171,326 179,684 INTANGIBLE ASSETS: Natural gas liquids sales and purchases contracts, net 85,302 84,304 Goodwill, net 444,219 435,115 Total intangible assets 529,521 519,419 UNREALIZED GAINS ON MARK-TO-MARKET AND HEDGING TRANSACTIONS 37,813 21,685 OTHER NONCURRENT ASSETS 91,840 89,504 TOTAL ASSETS $ 6,667,893 $ 6,565,601 CURRENT LIABILITIES: Accounts payable: Trade $ 764,245 $ 656,126 Affiliates 12,551 77,009 Other 36,661 45,786 Short term debt 105,072 215,094 Unrealized losses on mark-to-market and hedging transactions 203,111 245,469 Accrued interest payable 59,637 59,294 Accrued taxes other than income 24,217 31,059 Other 100,341 89,427 Total current liabilities 1,305,835 1,419,264 DEFERRED INCOME TAXES 12,883 11,740 LONG TERM DEBT 2,263,236 2,255,508 UNREALIZED LOSSES ON MARK-TO-MARKET AND HEDGING TRANSACTIONS 33,401 15,336 OTHER LONG TERM LIABILITIES 127,828 88,370 MINORITY INTERESTS 122,424 124,820 PREFERRED MEMBERS’ INTEREST 200,000 200,000 COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS’ EQUITY: Members’ interest 1,709,290 1,709,290 Retained earnings 907,798 806,119 Accumulated other comprehensive loss (14,802 ) (64,846 ) Total members’ equity 2,602,286 2,450,563 TOTAL LIABILITIES AND MEMBERS’ EQUITY $ 6,667,893 $ 6,565,601 Six Months Ended June 30, 2004 2003 Cash flows from operating activities: Net income $ 264 $ 111 Adjustments to reconcile net income to net cash provided by operating activities: Income from discontinued operations (5 ) (37 ) Cumulative effect of change in accounting principles — 23 Depreciation and amortization 150 150 Distributions received in excess of earnings from unconsolidated affiliates 7 7 Other, net 3 10 Change in operating assets and liabilities which provided (used) cash: Accounts receivable (89 ) (243 ) Accounts receivable from affiliates 16 128 Inventories 1 24 Net unrealized gains on mark-to-market and hedging transactions (11 ) (32 ) Accounts payable 108 146 Accounts payable to affiliates 3 (59 ) Accrued interest payable — — Other (20 ) (7 )
Net cash provided by operating activities 427 221
Cash flows from investing activities: Capital expenditures (132 ) (66 ) Consolidation of previously unconsolidated investment 6 — Contributions to minority interests, net — (1 ) Proceeds from sale of discontinued operations 62 90 Proceeds from sales of assets 2 5
Net cash (used in) provided by investing activities (62 ) 28
Cash flows from financing activities: Payment of debt (9 ) (115 ) Payment of dividends and distributions to members (148 ) (10 )
Net cash used in financing activities (157 ) (125 )
Effect of foreign exchange rate changes on cash — (1 ) Effect of discontinued operations on cash 2 10
Net increase in cash and cash equivalents 210 133 Cash and cash equivalents, beginning of period 43 35
Cash and cash equivalents, end of period $ 253 $ 168
Supplementary cash flow information: Cash paid for interest (net of amounts capitalized) $ 78 $ 81
See Condensed Notes to Consolidated Financial Statements.
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DUKE ENERGY FIELD SERVICES, LLC
1. General
Duke Energy Field Services, LLC (with its consolidated subsidiaries, “us”, “we”, “our” or the “Company” or “Field Services LLC”) operates in the two principal segments of the midstream natural gas industry of (1) natural gas gathering, compression, treatment, processing, transportation, marketingtrading and tradingmarketing and storage; and (2) natural gas liquids (“NGLs”NGL”), fractionation, transportation, marketing and trading.trading and marketing. Duke Energy Corporation (“Duke Energy”) owns 69.7% of the Company’s outstanding member interests and ConocoPhillips owns the remaining 30.3%.
2. Accounting Policies
Consolidation —The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not operate these investments and as a result does not have the ability to exercise control, in which case, they are accounted for using the equity method.
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 and cash flows for the respective interim periods. Amounts reportedThese consolidated financial statements and other information included in this quarterly report on Form 10-Q should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the interim Consolidated Statements of Operations are not necessarily indicative of amounts expectedconsolidated financial statements and notes thereto included in our annual report on Form 10-K for the respective annual periods.fiscal year ended December 31, 2003.
2. Summary of Significant Accounting Policies
Consolidation —The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating intercompany transactions and balances, and variable interest entities where we are the primary beneficiary. Investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Investments greater than 50% are consolidated unless we do not have the ability to exercise control, in which case, they are accounted for using the equity method.
Use of Estimates —Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.
Inventories— Inventories consist primarily of materials and supplies and natural gas and NGLs held in storage for transmission, marketing and sales commitments. Inventories are recorded at the lower of cost or market value using the average cost method. Historically, since January 2001, natural gas storage arbitrage inventories were marked to market. However, effective January 1, 2003, in accordance with the Financial Accounting Standard Board’s (“FASB”) Emerging Issues Task Force’s (“EITF”) rescission of Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” all gas storage inventory is now recorded at the lower of cost or market using the average cost method (see “New Accounting Standards” below).
Accounting for Hedges and Commodity Trading and Marketing Activities— All derivativesEach derivative not qualifying for the normal purchases and sales exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities,” as amended, areis recorded on a gross basis in the Consolidated Balance Sheets at theirits fair value as Unrealized Gainsgains or Unrealized Losseslosses on Mark-to-Marketmark-to-market and Hedging Transactions. Prior to the implementation of the remaining provisions of EITF Issue No. 02-03, “Issues Involvedhedging transactions. Derivative assets and liabilities remain classified in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” on January 1, 2003, certain non-derivative energy trading contracts were also recorded on the Consolidated Balance Sheets as Unrealized gains or Unrealized losses on mark-to-market or hedging transactions at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Seeuntil the Cumulative Effect of Changes in Accounting Principles section below for further discussion of the implementation of the provisions of EITF Issue No. 02-03.contractual delivery period occurs.
Effective January 1, 2003, in connection with the implementation of the remaining provisions of EITF Issue No. 02-03, the Company designateswe designate each energy commodity derivative as either trading or non-trading. Certain non-tradingFor each of our derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations are further designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or sale contract, while certain non-trading derivatives remain undesignated.follows:
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Classification of Contract | Accounting Method | Presentation of Gains & Losses or Revenue & Expense | ||
Trading Derivatives | Mark-to-marketa | Net basis in Trading and marketing net margin | ||
Non-Trading Derivatives: | ||||
Cash Flow Hedge | Hedge methodb | Gross basis in the same income statement category as the related hedged item | ||
Fair Value Hedge | Hedge methodb | Gross basis in the same income statement category as the related hedged item | ||
Normal Purchase or Normal Sale | Accrual methodc | Gross basis upon settlement in the corresponding income statement category based on commodity type | ||
Non-Trading Mark-to- Market | Mark-to-marketa | Net basis in Trading and marketing net margin |
a Mark-to-market- An accounting method whereby the change in the fair value of the asset or liability is recognized in the Consolidated Statements of Operations in Trading and marketing net margin during the current period.
b Hedge method- An accounting method whereby the change in the fair value of the asset or liability is recorded in the Consolidated Balance Sheets and there is no recognition in the Consolidated Statements of Operations for the effective portion until the hedged transaction occurs.
c Accrual method- An accounting method whereby there is no recognition in the Consolidated Statements of Operations for changes in fair value of a contract until the service is provided or the associated delivery of product occurs.
For derivatives designated as a cash flow hedge contracts, the Companyor a fair value hedge, we formally assesses,assess, both at the inception of the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. The Company excludesWe exclude the time value of the options when assessing hedge effectiveness.
When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating the open positions held in an orderly manner over a reasonable time period under current conditions. Changes in market prices 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 and Marketing — A favorable or unfavorable price movement of any derivative contract held for trading and marketing purposes is reported as Trading and Marketing Net Marginmarketing net margin in the Consolidated Statements of Operations. An offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized Gainsgains or Unrealized Losseslosses on Mark-to-Marketmark-to-market and Hedging Transactions.hedging transactions. When a contract is settled,the contractual delivery period occurs, the realized gain or loss is reclassified to aan account receivable or payable account. Settlement has no revenue presentation effect on the Consolidated Statements of Operations.
See the “New Accounting Standards” section below for a discussion of the implications of EITF Issue 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” on the accounting for trading activities subsequent to October 25, 2002.payable.
Commodity Cash Flow Hedges — The fair value of a derivative designated as a cash flow hedge is recorded in the Consolidated Balance Sheets as Unrealized gains or Unrealized losses on mark-to-market and hedging transactions. The effective portion of the change in fair value of a derivative designated and qualified as a cash flow hedge is includedrecorded in the Consolidated Balance Sheets as Accumulated Other Comprehensive Income (Loss)other comprehensive income (“AOCI”) until earnings are affected byand the ineffective portion is recorded in the Consolidated Statements of Operations. During the period in which the hedged item. Settlementtransaction occurs, amounts of cash flow hedgesin AOCI associated with the hedged transaction are removed from AOCI and recorded inreclassified to the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinuesWe discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, withvalue; however, subsequent changes in its fair value are recognized in current-periodcurrent period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until earnings are affected by the hedged item,transaction occurs, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were accumulatedpreviously deferred in AOCI will be immediately recognized in current-periodcurrent
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period earnings. At June 30, 2004 and December 31, 2003, $16 million and $29 million, respectively, of losses related to cash flow hedges were deferred in AOCI.
Commodity Fair Value Hedges — Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge are included in the Consolidated Statements of Operations as Sales of Natural Gasnatural gas and Petroleum Productspetroleum products and Purchases of Natural Gasnatural gas and Petroleum Products,petroleum products, as appropriate.appropriate, and are included in the Consolidated Balance Sheets as Unrealized gains or Unrealized losses on mark-to-market and hedging transactions. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of 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,current assets, Other Noncurrent Assets,noncurrent assets, Other Current Liabilitiescurrent liabilities or Other Long Term Liabilities,long term liabilities, as appropriate.
Interest Rate Fair Value Hedges — The CompanyWe periodically entersenter into interest rate swaps to convert some of itsour 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’sour hedged fixed-rate debt is carried at fair value. The terms of the outstanding swapswaps match those of the associated debt which permits the assumption of no ineffectiveness, as defined by SFAS No. 133. As such, for the life of the swapswaps, no ineffectiveness will be recognized.
Income TaxesDistributions –— TheUnder the terms of our Limited Liability Company isAgreement (the “LLC Agreement”), we are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The distributions areLLC Agreement, as amended, provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either
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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 ConocoPhillips. During the six months ended June 30, 2004, we paid distributions of $11 million based on estimated annual taxable income allocated to the members according to their respective ownership percentages. As of June 30, 2004, additional distributions payable of $5 million were included in Other current liabilities in the Consolidated Balance Sheets.
In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to Duke Energy and ConocoPhillips. The board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. The LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members. During the six months ended June 30, 2004, with the approval of both members, we paid a total dividend of $137 million to the members, allocated in accordance with their respective ownership percentages.
Stock-Based Compensation— Under Duke Energy’s 1998 Long Term Incentive Plan, stock options for Duke Energy’s common stock may be granted to the Company’sour key employees. The Company accountsWe account for stock-based compensation using the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Under this method, any compensation cost is measured as the quoted market price of stock at the date of the grant less the amount an employee must pay to acquire the stock. Since the exercise price for all options granted under those plansthe plan was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants and phantom stock awards and stock-based performance awards are recorded as compensation cost over the required vesting period, as compensation cost, based on the marketfair value on the date of grant. Performance awards are recorded as compensation cost over the required vesting period, based on the fair value of the awards at the balance sheet date.
The following disclosures reflecttable shows what earnings available for members’ interest would have been if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock options and reflects the provisions of SFAS No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.”
The following table shows what earnings available for members’ interest would have been if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for7
Pro Forma Stock-Based Compensation” to all stock-based compensation awards.
Three months ended, | Six month ended, | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Pro Forma Stock-Based Compensation | ||||||||||||||||
(in thousands) | 2003 | 2002 | 2003 | 2002 | ||||||||||||
Earnings (Deficit) available for members’ interest, as reported | $ | 77,769 | $ | (28,469 | ) | $ | 101,679 | $ | (52,594 | ) | ||||||
Add: stock-based compensation expense included in reported net income (loss) | 387 | 314 | 637 | 615 | ||||||||||||
Deduct: total stock-based compensation expense determined under fair value-based method for all awards | (2,078 | ) | (2,117 | ) | (3,240 | ) | (3,757 | ) | ||||||||
Pro forma earnings (deficit) available for members’ interest | $ | 76,078 | $ | (30,272 | ) | $ | 99,076 | $ | (55,736 | ) | ||||||
Three months ended | Six months ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(millions) | 2004 | 2003 | 2004 | 2003 | ||||||||||||
Earnings available for members’ interest, as reported | $ | 130 | $ | 78 | $ | 264 | $ | 102 | ||||||||
Add: stock-based compensation expense included in reported net income | 1 | — | 1 | — | ||||||||||||
Deduct: total stock-based compensation expense determined under fair value-based method for all awards | (2 | ) | (2 | ) | (2 | ) | (3 | ) | ||||||||
Pro forma earnings available for members’ interest | $ | 129 | $ | 76 | $ | 263 | $ | 99 | ||||||||
Accumulated Other Comprehensive Income (Loss) —The components of and changes in accumulated other comprehensive income (loss) are as follows:
Net | Accumulated | |||||||||||
Accumulated Other Comprehensive | Foreign | Unrealized | Other | |||||||||
Income (Loss) | Currency | (Losses) Gains on | Comprehensive | |||||||||
(in thousands) | Adjustments | Cash Flow Hedges | (Loss) Income | |||||||||
Balance as of December 31, 2002 | $ | (6,728 | ) | $ | (58,118 | ) | $ | (64,846 | ) | |||
Other comprehensive income changes during the period | 45,059 | 4,985 | 50,044 | |||||||||
Balance as of June 30, 2003 | $ | 38,331 | $ | (53,133 | ) | $ | (14,802 | ) | ||||
7Accumulated Other Comprehensive Income
Net | Accumulated | |||||||||||
Foreign | Unrealized | Other | ||||||||||
Currency | (Losses) Gains on | Comprehensive | ||||||||||
(millions) | Adjustments | Cash Flow Hedges | Income | |||||||||
Balance as of December 31, 2003 | $ | 53 | $ | (29 | ) | $ | 24 | |||||
Other comprehensive income changes during the period | (13 | ) | 13 | — | ||||||||
Balance as of June 30, 2004 | $ | 40 | $ | (16 | ) | $ | 24 | |||||
Cumulative Effect of ChangesChange in Accounting Principles— The CompanyWe adopted the provisions of EITF Issue 02-03 (“EITF 02-03”), “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” that required new non-derivative energy trading contracts entered into after October 25, 2002 to be accounted for under the accrual accounting basis. Non-derivative energy trading contracts recorded in the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair value were adjusted to historical cost via a cumulative effect adjustment of $5 million as a reduction to earnings in the first quarter of 2003.
We adopted the provisions of SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations” onObligations,” as of January 1, 2003.2003 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In accordance with the transition provisions of SFAS No. 143, the Companywe recorded asset retirement liabilities and a cumulative-effectcumulative effect adjustment of $17.4$18 million as a reduction to earnings in earnings. In addition, in accordance with the EITF’s October 2002 consensus on Issue No. 02-03, on January 1, 2003, the Company decreased its inventories from fair value to historical cost and recorded a $5.4 million cumulative-effect adjustment as a reduction in earnings.first quarter of 2003.
New Accounting Standards— In May 2003, the FASB issued SFAS No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.Equity” including the deferral of certain effective dates as a result of the provisions of FASB Staff Position 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Noncontrolling Interests Under FASB Statement No. 150, ‘Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity’.” SFAS No. 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in statements of financial positionthe consolidated balance sheets and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS No. 150 also requires disclosures about the nature and terms of the financial instruments and about alternative ways of settling the instruments. The provisions of SFAS No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, the Company will reclassify itswe reclassified our preferred members’ interest, which were mandatorily redeemable, of $200 million from mezzanine equity to long-term liabilities at its fair value of approximately $200 million. Future disbursementslong term debt and prospectively classified accrued or paid distributions on these securities, which had previously been classified as dividends, on these preferred members’ interest will be classified as interest expense. During 2003, we redeemed the remaining $200 million of these securities in cash.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component, and amends the definition of an underlying to conform it to language used in FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, SFAS No. 149 also incorporates certain of the Derivative Implementation Group Implementation Issues. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The guidance is to be applied to hedging relationships on a prospective basis. The Company does not anticipate SFAS No. 149 will have a material impact on its consolidated results of operations, cash flows or financial position.8
In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46Entities” which requires an entity to consolidate a variable interest entity if it is the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity’s activities. The primary beneficiary isentity. We adopted the party that absorbs a majorityprovisions of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, and its related interpretations (“FIN 46 is required to be applied46R”) in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively withquarter of 2004. As a cumulative-effect adjustmentresult, we consolidated one entity, previously accounted for under the equity method of accounting, on January 1, 2004. This entity, which is a substantive entity, had total assets of approximately $92 million as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. The Company has not identified any variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and continues to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. It is reasonably possible that the Company will disclose information about variable interest entities upon the application1, 2004. Adoption of FIN 46, primarily as the result of investments it has in certain unconsolidated affiliates. For all of these unconsolidated affiliates, the Company believes that its maximum exposure to loss would be equal to its investment in these entities, plus its potential obligations under its guarantees of unconsolidated debt. At June 30, 2003, the Company’s total investment in, plus the value of any guaranteed debt for entities that have a reasonable possibility to be determined to be variable interest entities, was approximately $160.7 million. The Company continues to assess FIN 46 but does not anticipate that it will have a46R had no material impacteffect on itsour consolidated results of operations, cash flows or financial position.
In November 2002, the FASB issued Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It
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also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company adopted the initial recognition and measurement provisions of FIN 45 effective January 1, 2003. Adoption of the new interpretation had no material effect on the Company’s consolidated results of operations, cash flows or financial position.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The Company adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost would have been recognized at the date of an entity’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.
In June 2002,July 2003, the EITF reached a partial consensus onin EITF Issue No. 02-03, “Issues Involved in03-11 (“EITF 03-11”), “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative ContractsInstruments and Hedging Activities, and Not Held for Trading Purposes, and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that effective for periods ending after July 15, 2002, mark-to-marketdetermining whether realized gains and losses on energy tradingderivative contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice.
In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, must now be recorded at the lower of cost or market and are reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market via a cumulative-effect adjustment of $5.4 million as a reduction to 2003 earnings. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.
In October 2002, the EITF also reached a consensus on Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shownreported on a net or gross basis inis a matter of judgment that depends on the income statement. Gainsrelevant facts and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection withcircumstances. In analyzing the guidance in Issue No.facts and circumstances, EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.Agent” and Opinion No. 29, “Accounting for Nonmonetary Transactions,” Upon applicationshould be considered. EITF 03-11 is effective for transactions or arrangements entered into after September 30, 2003. The adoption of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under Issue No. 98-10. Accordingly, for the three and six months ended June 30, 2003, derivative instruments that are held for trading and marketing purposes and are accounted for under mark-to-market accounting are included in Trading and Marketing Net Margin on the Consolidated Statements of Operations. For the three and six months ended June 30, 2002, Trading and Marketing Net Margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales) that no longer qualify for net presentation after the rescission of Issue No. 98-10. The new gross versus net revenue presentation requirementsEITF 03-11 had no impactmaterial effect on operating incomeour consolidated results of operations, cash flows or net income.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the
9
asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, the Company recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.position.
In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. The Company is currently assessing the impactadoption of EITF Issue No. 01-08 will havehad no material effect on itsour consolidated results of operations, cash flows or financial position.
Reclassifications—Certain prior period amounts have been reclassified in the Consolidated Financial Statements and notes thereto to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amount of approximately $223 million and $459 million, respectively, for the three and six months ended June 30, 2003. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations during the six months ended June 30, 2003. Management has concluded that these reclassifications are not material to the fair presentation of our financial statements.
3. Acquisitions and Dispositions
On March 10, 2004, we entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips, a related party, for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities. The transaction closed during the second quarter of 2004.
In February 2004, we sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million. These assets comprised a component of the Company for purposes of reporting discontinued operations. All prior period operations have been revised to reflect these assets as discontinued operations.
During the six months ended June 30, 2003, we sold gathering, transmission and processing assets to two separate buyers for a combined sales price of approximately $90 million. These assets comprised a component of the Company for purposes of reporting discontinued operations. All prior period operations have been revised to reflect these assets as discontinued operations.
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The following table sets forth selected financial information associated with the assets discussed above which are accounted for as discontinued operations:
Three | Six | |||||||||||||||
Months Ended | Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||||||
(millions) | (millions) | |||||||||||||||
Revenues | $ | — | $ | 98 | $ | 14 | $ | 237 | ||||||||
Operating income | — | 5 | 2 | 11 | ||||||||||||
Gain on sale | — | 26 | 3 | 26 | ||||||||||||
Income from discontinued operations | $ | — | $ | 31 | $ | 5 | $ | 37 | ||||||||
4. Derivative Instruments, Hedging Activities and Credit and Risk
Commodity price risk —The Company’s principal operations of gathering, processing, transportation, marketing and trading and storage of natural gas, and the accompanying operations of fractionation, transportation, trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, the Company has an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw gas. Risk is also dependent on the types and mechanisms for sales of natural gas and natural gas liquid products produced, processed, transported or stored.
Energy trading (market) risk —Certain of the Company’s subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.
Corporate economic risks —The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with debt. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.
Counterparty risks —The Company sells various commodities (i.e., natural gas, NGLs and crude oil) to a variety of customers. The natural gas customers include local utilities, industrial consumers, independent power producers and merchant energy trading organizations. The NGLs customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGLs sales are made at market-based prices, including approximately 40% of NGLs production that is committed to ConocoPhillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015. This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On transactions where the Company is exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure.
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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 failure 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. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
Commodity cash flow hedges —The Company usesWe may, from time to time, use 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’sour 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 maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; and retaining a high percentage of potential upside relating to price increases of NGLs.
The Company usesWe use natural gas, crude oil and NGLsNGL swaps and options to hedge the impact of market fluctuations in the prices of NGLs,NGL, natural gas and other energy-related products. For the three and six months ended June 30, 2004, the recognition in the Consolidated Statements of Operations of the cumulative changes in the fair value of these hedge instruments reduced revenues by $23 million and $41 million, respectively, compared to $24 million and $63 million, respectively, in the same periods of 2003. The above changes in the fair value of these hedge instruments include the effects of any ineffectiveness, which for the six months ended June 30, 2004 and 2003, the Company recognizedwere a net loss of $63.2 million, of which a $3.0$1 million gain represented the total ineffectiveness of all cash flow hedges and a $66.2$3 million loss, represented the total derivative settlements.respectively. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to any forecasted transactions that are not probable of occurring.
Gains and losses on derivative contracts that are reclassified from AOCI to current period earnings are included in the line item in which the hedged item is recorded. As of June 30, 2003, $51.42004, $16 million of the remaining deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings duringwithin the next 12 months as the hedgehedged transactions occur; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. The maximumremaining term over which the Company iswe are currently hedging itsour exposure to the variability of future cash flows is three years.through the end of 2004.
Commodity fair value hedges—The Company uses We use 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 hedgesWe may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce the Company’sour exposure to fixed price risk via swapping out the fixed price risk for a floating price position (New York Mercantile Exchange or index based).
For the six months ended June 30, 2003,2004, the gains or losses representing the ineffective portion of the Company’sour fair value hedges were not significant.material. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The CompanyWe did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.
Interest rate fair value hedge hedges—In October 2001, the Companywe entered into an interest rate swap to convert the fixed interest rate$250 million of $250.0 million offixed-rate debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges are also at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swap meetsswaps meet conditions which permit the assumption of no ineffectiveness, as defined by SFAS No. 133. As such, for the life of the swapswaps no ineffectiveness will be recognized. As of June 30, 2003,2004, the fair value of the interest rate swap of $16.3swaps was a $6 million wasasset, which is included in the Consolidated Balance Sheets as Unrealized Gainsgains or Losseslosses on Tradingmark-to-market and Hedging Transactionshedging transactions with an offset to the underlying debt included in Long Term Debt.term debt.
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Commodity Derivatives — Trading and Marketing—The trading and marketing of energy related products and services exposes the Companyus to the fluctuations in the market values of traded instruments. We manage our trading and marketed instruments. The Company manages its traded and marketed instrument portfoliosmarketing portfolio with strict policies which limit exposure to market risk and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement.
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4.5. Asset Retirement Obligations
SFAS No. 143,“Accounting for Asset Retirement Obligations.”In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. The Company’s asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way agreements and contractual leases for land use.Obligation
SFAS No. 143 requires thatThe following table summarizes changes in the fair value of a liability for an asset retirement obligation be recognizedfor the six months ended June 30, 2004 and 2003, respectively.
Six | ||||||||
Months Ended | ||||||||
June 30, | ||||||||
Reconciliation of Asset Retirement Obligation (millions) | 2004 | 2003 | ||||||
Balance as of January 1 | $ | 45 | $ | 43 | ||||
Accretion expense | 2 | 3 | ||||||
Liabilities incurred | 2 | — | ||||||
Liabilities settled | (1 | ) | (3 | ) | ||||
Balance as of June 30 | $ | 48 | $ | 43 | ||||
6. Goodwill and Other Intangibles
The changes in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of goodwill for the associated asset. This additionalsix months ended June 30, 2004 are as follows:
Foreign | ||||||||||||||||
Purchase | Currency | |||||||||||||||
Balance | Price | Exchange | Balance | |||||||||||||
December 31, 2003 | Adjustments | Adjustments | June 30, 2004 | |||||||||||||
(millions) | ||||||||||||||||
Natural gas gathering, processing, transportation, marketing and storage | $ | 407 | $ | — | $ | (2 | ) | $ | 405 | |||||||
NGL fractionation, transportation, marketing and trading | 40 | — | — | 40 | ||||||||||||
Total consolidated | $ | 447 | $ | — | $ | (2 | ) | $ | 445 | |||||||
There were no impairments of goodwill during the six months ended June 30, 2004.
The gross carrying amount is then depreciated overand accumulated amortization for commodity sales and purchases contracts are as follows:
June 30, | December 31, | |||||||
2004 | 2003 | |||||||
(millions) | ||||||||
Commodity sales and purchases contracts | $ | 127 | $ | 127 | ||||
Accumulated amortization | (52 | ) | (47 | ) | ||||
Commodity sales and purchases contracts, net | $ | 75 | $ | 80 | ||||
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During the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.
The Company identified various assets as having an indeterminate life in accordance with SFAS No. 143, which do not trigger a requirement to establish a fair value for future retirement obligationssix months ended June 30, 2004 and 2003, we recorded amortization expense associated with such assets. These assets include certain pipelines, processing plantscommodity sales and distribution facilities. A liabilitypurchases contracts of $5 million. The average remaining amortization period for these asset retirement obligations will be recorded if and when a future retirement obligationcontracts is identified.
SFAS No. 143 was effectiveapproximately 7 years. Estimated amortization for fiscal years beginning after June 15, 2002, and was adopted by the Company on January 1, 2003. At January 1, 2003, the implementation of SFAS No. 143 resulted in a net increase in total assets of $25.1 million, consisting of an increase in net property, plant and equipment. Long term liabilities increased by $42.5 million, which represents the establishment of an asset retirement obligation liability. A cumulative-effect of a change in accounting principle adjustment of $17.4 million was recorded in the first quarter of 2003, as a reduction in earnings.
The following table shows the asset retirement obligation liability as though SFAS No. 143 had been in effectthese contracts for the prior three years.
Pro forma Asset Retirement Obligation | (in thousands) | |||
January 1, 2000 | $ | 13,493 | ||
December 31, 2000 | 31,561 | |||
December 31, 2001 | 38,879 | |||
December 31, 2002 | 42,549 |
Estimated Amortization | ||||
(millions) | ||||
2004 | $ | 4 | ||
2005 | 8 | |||
2006 | 8 | |||
2007 | 8 | |||
2008 | 8 | |||
Thereafter | 39 | |||
Total | $ | 75 | ||
The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table rolls forward the asset retirement obligation from the balance at December 31, 2002 to June 30, 2003.
Reconciliation of Asset Retirement Obligation | (in thousands) | |||
Balance as of January 1, 2003 | $ | 42,549 | ||
Accretion expense | �� | 1,713 | ||
Other | (1,761 | ) | ||
Balance as of June 30, 2003 | $ | 42,501 | ||
5. Financing
Credit Facility with Financial Institutions —On March 28, 2003, the Company26, 2004, we entered into a new credit facility (the “Facility”). The Facility replaces the credit facility that matured on March 28, 2003.26, 2004. The Facility is used to support the Company’sour commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 26, 2004,25, 2005; however, any outstanding loansborrowings under the Facility at maturity may, at the Company’sour option, be converted to a one-year term loan. The Facility is a $350.0$250 million revolving credit facility, all of which $100.0 million can be used for letters of credit. The Facility requires the Companyus to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each
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fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA, asis defined by the Facility, is defined to be earnings before interest, taxes and depreciation and amortization and other adjustments); and contains various restrictions applicable to dividends and other payments to the Company’s members.. The Facility bears interest at a rate equal to, at the Company’sour option and based on the Company’sour current debt rating, either (1) LIBOR plus 1.25%1.125% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.25%0.125% per year and (b) the Federal Funds rate plus 0.75%0.625% per year. At June 30, 2003,2004, there were no borrowings or letters of credit drawn against the Facility.
On March 28, 2003, the Companywe also entered into a $100.0$100 million funded short-term loan with a bank (the “Short-Term Loan”). The Short-Term Loan iswas used for working capital and other general corporate purposes. The Short-Term Loan matures oncontained an original maturity of September 30, 2003, and may bebut was repaid at any time. The Short-Term Loan has the same financial covenants as the Facility. The Short-Term Loan bears interest at a rate equal to, at the Company’s option, either (1) LIBOR plus 1.35% per year or (2) the higher of (a) the bank’s prime rate and (b) the Federal Funds rate plus 0.50% per year. Subsequent to June 30,by August 2003 the Company repaid the entire Short-Term Loan with funds generated from asset sales and operations.
6. On November 3, 2003, we executed a $32 million irrevocable standby letter of credit, to be used to secure transaction exposure with a counterparty, which expired on May 15, 2004.
Preferred Financing –Upon adoption of SFAS 150 on July 1, 2003, we reclassified our preferred members’ interest, which are mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt. During 2003, subsequent to the reclassification, we redeemed the remaining $200 million. Beginning on July 1, 2003, accrued or paid distributions previously classified as dividends on the preferred members’ interest are prospectively classified as interest expense in the Consolidated Statements of Operations.
8. Commitments and Contingent Liabilities
Litigation— The midstream natural gas industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. The Company and its subsidiariesWe are currently named as defendants in some of these cases. Management believes the Company and its subsidiarieswe have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend. Management believes that, the final disposition ofbased on currently known information, these proceedings will not have a material adverse effect on theour consolidated results of operations, or financial position or cash flows.
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General Insurance— We carry insurance coverage, with an affiliate of Duke Energy, that management believes is consistent with companies engaged in similar commercial operations with similar type properties. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the Company.replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
7. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.
Environmental- The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGL and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States and Canadian laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Severance Program— On October 30, 2003, we communicated a company-wide voluntary and involuntary severance program to our employees to reduce approximately 6% of our workforce. The plan was completed on December 8, 2003 and included the reduction of 160 employees over the period from December 2003 through 2004. The severance liability that was recorded in the fourth quarter of 2003 was $6 million at December 31, 2003. Included in General and administrative expense in the Consolidated Statement of Operations during first quarter of 2004, the Company expensed an additional $1 million related to this severance program. The following table summarizes changes in the severance liability for the six months ended June 30, 2004.
Reconciliation of Severance liability (millions) | ||||
Balance as of December 31, 2003 | $ | 6 | ||
Additional severance expense | 1 | |||
Severance paid | (6 | ) | ||
Balance as of June 30, 2004 | $ | 1 | ||
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9. Business Segments
The Company operatesWe operate in two principal business segments as follows:segments:
(1) natural gas gathering, compression, treatment, processing, transportation marketingand storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and storage (“Naturalmarketing (the “Natural Gas Segment”), and
(2) NGLsNGL fractionation, transportation, marketing and trading, (“NGLsfrom which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGL (the “NGL Segment”).
Intersegment activity is primarily related to the sale of NGL from the Natural Gas Segment to the NGL Segment at market based transfer prices.
These segments are monitored separately by management for performance against itsour internal forecast and are consistent with the Company’sour internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. The following table includes the components of theMargin is a performance measures usedmeasure utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2. Foreign operations are not material and are therefore not separately identified.
13 The following tables set forth our segment information.
Three months ended June 30, 2004 (millions):
Intersegment | ||||||||||||||||||||
Natural Gas | NGL | Eliminations | Other | Total | ||||||||||||||||
Segment | Segment | (a) | (c) | Company | ||||||||||||||||
Operating Revenues | $ | 2,177 | $ | 482 | $ | (277 | ) | $ | — | $ | 2,382 | |||||||||
Gross Margin(b) | 368 | 12 | — | — | 380 | |||||||||||||||
Other operating and administrative costs | 104 | 3 | — | 41 | 148 | |||||||||||||||
Depreciation and amortization | 68 | 3 | — | 4 | 75 | |||||||||||||||
Earnings from unconsolidated affiliates | 14 | — | — | — | 14 | |||||||||||||||
Interest expense | — | — | — | 39 | 39 | |||||||||||||||
Income from continuing operations before income taxes | $ | 210 | $ | 6 | $ | — | $ | (84 | ) | $ | 132 | |||||||||
Capital Expenditures | $ | 107 | $ | — | $ | — | $ | — | $ | 107 | ||||||||||
Three months ended June 30, 2003 (millions):
Intersegment | ||||||||||||||||||||
Natural Gas | NGL | Eliminations | Other | Total | ||||||||||||||||
Segment | Segment | (a) | (c) | Company | ||||||||||||||||
Operating Revenues | $ | 1,872 | $ | 450 | $ | (266 | ) | $ | — | $ | 2,056 | |||||||||
Gross Margin(b) | 302 | 8 | — | — | 310 | |||||||||||||||
Other operating and administrative costs | 111 | 2 | — | 41 | 154 | |||||||||||||||
Depreciation and amortization | 66 | 4 | — | 5 | 75 | |||||||||||||||
Earnings from unconsolidated affiliates | 11 | 1 | — | — | 12 | |||||||||||||||
Interest expense | — | — | — | 42 | 42 | |||||||||||||||
Income from continuing operations before income taxes | $ | 136 | $ | 3 | $ | — | $ | (88 | ) | $ | 51 | |||||||||
Capital Expenditures | $ | 31 | $ | — | $ | — | $ | 1 | $ | 32 | ||||||||||
14
Six months ended June 30, 2004 (millions):
Intersegment | ||||||||||||||||||||
Natural Gas | NGL | Eliminations | Other | Total | ||||||||||||||||
Segment | Segment | (a) | (c) | Company | ||||||||||||||||
Operating Revenues | $ | 4,381 | $ | 1,060 | $ | (657 | ) | $ | — | $ | 4,784 | |||||||||
Gross Margin(b) | 713 | 32 | — | — | 745 | |||||||||||||||
Other operating and administrative costs | 196 | 5 | — | 82 | 283 | |||||||||||||||
Depreciation and amortization | 135 | 7 | — | 8 | 150 | |||||||||||||||
Earnings from unconsolidated affiliates | 31 | — | — | — | 31 | |||||||||||||||
Interest expense | — | — | — | 79 | 79 | |||||||||||||||
Income from continuing operations before income taxes | $ | 413 | $ | 20 | $ | — | $ | (169 | ) | $ | 264 | |||||||||
Capital Expenditures | $ | 130 | $ | — | $ | — | $ | 2 | $ | 132 | ||||||||||
The following table sets forth the Company’s segment information.
Three | Six | |||||||||||||||||
Months Ended | Months Ended | |||||||||||||||||
June 30, | June 30, | |||||||||||||||||
2003 | 2002 | 2003 | 2002 | |||||||||||||||
(in thousands) | ||||||||||||||||||
Operating revenues (b): | ||||||||||||||||||
Natural Gas, including trading and marketing net margin | $ | 1,916,801 | $ | 1,335,959 | $ | 4,353,905 | $ | 2,361,192 | ||||||||||
NGLs, including trading and marketing net margin | 447,931 | 317,412 | 952,105 | 639,212 | ||||||||||||||
Intersegment (a) | (486,959 | ) | (352,439 | ) | (1,034,408 | ) | (616,703 | ) | ||||||||||
Total operating revenues | $ | 1,877,773 | $ | 1,300,932 | $ | 4,271,602 | $ | 2,383,701 | ||||||||||
Margin: | ||||||||||||||||||
Natural Gas, including trading and marketing net margin | $ | 308,933 | $ | 222,319 | $ | 592,766 | $ | 449,387 | ||||||||||
NGLs, including trading and marketing net margin | 6,221 | 10,614 | 24,174 | 26,669 | ||||||||||||||
Total margin | $ | 315,154 | $ | 232,933 | $ | 616,940 | $ | 476,056 | ||||||||||
Other operating and administrative costs: | ||||||||||||||||||
Natural Gas | $ | 112,664 | $ | 105,338 | $ | 216,481 | $ | 212,682 | ||||||||||
NGLs | 1,861 | 2,315 | 4,320 | 4,775 | ||||||||||||||
Corporate | 40,327 | 39,062 | 79,758 | 78,270 | ||||||||||||||
Total other operating costs | $ | 154,852 | $ | 146,715 | $ | 300,559 | $ | 295,727 | ||||||||||
Depreciation and amortization: | ||||||||||||||||||
Natural Gas | $ | 67,890 | $ | 65,309 | $ | 136,738 | $ | 131,015 | ||||||||||
NGLs | 3,471 | 2,305 | 6,677 | 5,623 | ||||||||||||||
Corporate | 4,907 | 1,546 | 8,663 | 3,949 | ||||||||||||||
Total depreciation and amortization | $ | 76,268 | $ | 69,160 | $ | 152,078 | $ | 140,587 | ||||||||||
Equity in earnings of unconsolidated affiliates: | ||||||||||||||||||
Natural Gas | $ | 11,416 | $ | 6,870 | $ | 24,255 | $ | 12,519 | ||||||||||
NGLs | 400 | 966 | (385 | ) | 1,387 | |||||||||||||
Total equity in earnings of unconsolidated affiliates | $ | 11,816 | $ | 7,836 | $ | 23,870 | $ | 13,906 | ||||||||||
Total corporate interest expense | $ | 41,759 | $ | 42,295 | $ | 84,497 | $ | 85,604 | ||||||||||
Income (loss) from continuing operations before income taxes: | ||||||||||||||||||
Natural Gas | $ | 139,795 | $ | 58,542 | $ | 263,802 | $ | 118,209 | ||||||||||
NGLs | 1,289 | 6,960 | 12,792 | 17,658 | ||||||||||||||
Corporate | (86,993 | ) | (82,903 | ) | (172,918 | ) | (167,823 | ) | ||||||||||
Total income (loss) from continuing operations before income taxes | $ | 54,091 | $ | (17,401 | ) | $ | 103,676 | $ | (31,956 | ) | ||||||||
Capital expenditures: | ||||||||||||||||||
Natural Gas | $ | 31,421 | $ | 46,998 | $ | 65,421 | $ | 149,426 | ||||||||||
NGLs | 25 | 6,717 | 52 | 6,896 | ||||||||||||||
Corporate | 1,292 | 5,285 | 2,177 | 8,881 | ||||||||||||||
Total capital expenditures | $ | 32,738 | $ | 59,000 | $ | 67,650 | $ | 165,203 | ||||||||||
As of | ||||||||||
June 30, | December 31, | |||||||||
2003 | 2002 | |||||||||
(in thousands) | ||||||||||
Total assets: | ||||||||||
Natural Gas | $ | 5,157,262 | $ | 5,187,704 | ||||||
NGLs | 259,713 | 293,398 | ||||||||
Corporate (c) | 1,250,918 | 1,084,499 | ||||||||
Total assets | $ | 6,667,893 | $ | 6,565,601 | ||||||
Intersegment | ||||||||||||||||||||
Natural Gas | NGL | Eliminations | Other | Total | ||||||||||||||||
Segment | Segment | (a) | (c) | Company | ||||||||||||||||
Operating Revenues | $ | 4,250 | $ | 951 | $ | (578 | ) | $ | — | $ | 4,623 | |||||||||
Gross Margin(b) | 581 | 25 | — | — | 606 | |||||||||||||||
Other operating and administrative costs | 214 | 4 | — | 79 | 297 | |||||||||||||||
Depreciation and amortization | 134 | 7 | — | 9 | 150 | |||||||||||||||
Earnings from unconsolidated affiliates | 24 | — | — | — | 24 | |||||||||||||||
Interest expense | — | — | — | 84 | 84 | |||||||||||||||
Income from continuing operations before income taxes | $ | 257 | $ | 14 | $ | — | $ | (172 | ) | $ | 99 | |||||||||
Capital Expenditures | $ | 64 | $ | — | $ | — | $ | 2 | $ | 66 | ||||||||||
As of | ||||||||
June 30, | December 31, | |||||||
2004 | 2003 | |||||||
(millions) | ||||||||
Total assets: | ||||||||
Natural Gas | $ | 4,957 | $ | 5,074 | ||||
NGL | 271 | 271 | ||||||
Corporate (c) | 1,488 | 1,169 | ||||||
Total assets | $ | 6,716 | $ | 6,514 | ||||
(a) | Intersegment sales represent sales of | |
(b) |
14
(c) | Includes Corporate expense items such as unallocated working capital, intercompany accounts and intangible and other assets. |
8.15
10. Guarantor’s Obligations Under Guarantees
At June 30, 2003, the Company wasOn January 1, 2004, we were the guarantor of approximately $94.1$3 million of debt associated with non-consolidated entities, of which $84.6 million is related to our 33.33% ownership interest in Discovery Producer Services, LLC (“Discovery”), and $9.5 million is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (“GGG”).for an affiliate. The guaranteed debt related to Discovery is due December 31, 2003, and is expected to be refinanced. The guaranteed debt related to GGG is scheduled to bewas repaid in full byin January 31,of 2004. In the event that the unconsolidated subsidiaries default on the debt payments, the Company would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At June 30, 2003, the Company had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.
The CompanyWe periodically entersenter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Typically, claimsClaims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The survivaleffective periods on these indemnification provisions generally have terms of one to five years, although some are longer. The Company’sOur maximum potential exposure under these indemnification agreements can rangevary depending on the nature of the claim and the particular transaction. The Company isWe are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At June 30, 2003, the Company2004, we had an approximate $1.5a liability of approximately $1 million liability recorded for theseknown liabilities related to outstanding indemnification provisions.
9. Accounting Adjustments16
During 2002, the Company completed a comprehensive account reconciliation project to review and analyze its balance sheet accounts. This account reconciliation project identified the following five categories where account adjustments were necessary: operating expense accruals; gas inventory adjustments; gas imbalances; joint venture and investment accounting; and other balance sheet accounts. As a result of this account reconciliation project, the Company recorded numerous adjustments in 2002. For the three and six months ended June 30, 2002, adjustments totaling approximately $18 million and $29 million may be related to corrections of accounting errors in prior periods. However, management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements. In addition, numerous items identified in the account reconciliation project resulted from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Accordingly, the corrections were made in the first six months 2002 financial statements.
10. Asset Sales
In the second quarter of 2003, the Company sold various gathering, transmission and processing assets, plus a minority interest in a partnership owning a gas processing plant, to two separate buyers for a combined sales price of approximately $90.2 million. These assets were included in the Company’s Natural Gas Segment as disclosed in Note 7. These assets comprised a component of the Company for purposes of reporting discontinued operations. All prior period operations have been revised to reflect these assets as discontinued operations.
15
The following table sets forth selected financial information associated with these assets accounted for as discontinued operations.
Three | Six | ||||||||||||||||
Months Ended | Months Ended | ||||||||||||||||
June 30, | June 30, | ||||||||||||||||
2003 | 2002 | 2003 | 2002 | ||||||||||||||
(in thousands) | |||||||||||||||||
Revenues | $ | 66,581 | $ | 48,779 | $ | 160,096 | $ | 85,445 | |||||||||
Operating income (loss) | $ | 2,502 | $ | (630 | ) | $ | 6,150 | $ | (774 | ) | |||||||
Gain on sale | 26,207 | — | 26,207 | — | |||||||||||||
Gain (loss) from discontinued operations | $ | 28,709 | $ | (630 | ) | $ | 32,357 | $ | (774 | ) | |||||||
11. Subsequent Events
In July 2003, the Company entered into an agreement to sell approximately 900 vehicles for approximately $14 million. This is a sale-leaseback transaction whereby the Company sold the vehicles but will lease them back over a one year lease term. The lease expires in July 2004, with annual extensions exercisable at the Company’s option. The future minimum lease payments under the lease are approximately $15 million. The Company does not have an option to purchase the leased vehicles at the end of the minimum lease term. As the proceeds from the sale of the vehicles are equal to the net book value of the vehicles, no gain or loss has been recognized.
In August 2003, the Company entered into a purchase and sale agreement to sell certain gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, plus or minus various adjustments that will be made at closing. The Company anticipates closing the transaction on September 30, 2003 with no significant book gain or loss.
For information on subsequent events related to financing matters, see Note 5, Financing.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion details the material factors that affected our historical financial condition and results of operations during the three and six months ended June 30, 20032004 and 2002.2003. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report.
Overview
We operate in the two principal business segments of the midstream natural gas industry:
16
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 NGLsNGL in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors. This limitation in scope is not currently expected to materially impact the results of our operations.
Effects of Commodity Prices
We are exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, depending on the type of contractual agreement, we receive fees or commodities from the producers to bring the raw natural gas from the well headwellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, dependingbased on the type of contractual agreement. Based on our current contract mix, we have a long NGLsNGL position and are sensitive to changes in NGLs prices. We also have a short natural gas position;position, however, the short natural gas position is less significant than the long NGLsNGL position.
We are also exposed Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $0.01 per gallon in the price of NGL and $0.10 per million Btus in the average price of natural gas would result in changes in commodity prices asannual pre-tax net income of approximately $(19) million and $1 million, respectively. In addition, a resultdecrease of our NGLs and natural gas trading activities. NGLs trading includes trading and storage at$1 per barrel in the Mont Belvieu, Texas and Conway, Kansas NGLs market centers to manage ouraverage price risk and provide additional services to our customers. Natural gas trading activities are supported by our ownership of a natural gas storage facility and various intrastate pipelines. We undertake these activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. We also execute NGLs proprietary trading, which includes commodities such as natural gas, NGLs, crude oil and refined products, based upon our knowledge and expertise obtained through the operationwould result in a change to annual pre-tax net income of our assets and our position as a leading NGLs marketer.approximately $(5) million.
During the first two quarterssix months of 2003,2004, approximately 75%80% of our gross margin wasis generated by commodity sensitive processing arrangements and approximately 25%20% of our gross margin was(excluding hedging and including earnings of unconsolidated affiliates) is generated by fee-based arrangements and marketing and trading activities.arrangements. We actively manage our commodity exposure as discussed below.
The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs,NGL, which in turn has historically been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs,NGL, 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 NGLsNGL and natural gas have been extremely volatile.
WeBased on historical trends, we generally expect NGLsNGL 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 by the demand generated by growth in the world economy. However, the relationship or correlation between crude oil prices and NGLs prices declined significantly during 2001 and 2002. In late 2002, this relationship strengthened and remained near historical trend levels during the first two quarters of 2003.
We believe that future natural gas prices will
17
be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. The price increases in crude oil, NGLs and natural gas experienced during 2000 and first half of 2001 spurred increased natural gas drilling activity. However, a decline in commodity prices in late 2001, continuing into 2002, negatively affected drilling activity. The average number of active naturaloil and gas rigs drilling in the United States were 170 and 1,005, respectively, as of America increasedJune 30, 2004, compared to 857 during the second quarter144 and 924, respectively, as of 2003 from 670 during the second quarter of 2002.June 30, 2003. This increase is mainly attributable to recent significant increases in natural gas prices which could result in sustained increases in drilling activity during 2003.2004. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.
To better address the risks associated with volatile commodity prices, we employ 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
17
NGLs NGL contracts to hedge a portion of the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative DisclosureDisclosures About Market Risk.” Our second quarter 2003 and 2002We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. The recognition in the Consolidated Statements of Operations of the cumulative changes in the fair value of these hedge instruments reduced the results of operations include a hedging loss of $23.6by $23 million and a hedging loss$24 million in the second quarter of $8.3 million,2004 and 2003, respectively. During the first six months of 2004 and 2003 and 2002the changes in fair value of our hedging activities resulted in a losscontracts reduced results of $63.2operations by $41 million and a loss of $0.9$63 million, respectively. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk”. The remaining term over which we are currently hedging losses incurred relateour exposure to hedges placed duringthe variability of future cash flows is through the end of 2004.
Effects of Our Raw Natural Gas Supply Arrangements
Our results are affected by the types of arrangements we use to process raw natural gas. We obtain access to raw natural gas and provide our midstream natural gas services principally under three types of processing contracts:
As defined in the terms of lowerthe above arrangements we sell condensate, which is generally similar to crude oil, which is produced in association with natural gas gathering and processing.
In 2004 and 2003, we converted a portion of our keep-whole contracts to percentage-of-proceeds contracts and we amended a portion of our keep-whole contracts to add a minimum fee clause. This had the impact of reducing the Company’s exposure to natural gas and NGL prices.
Our current mix of percentage-of-proceeds contracts (where we are exposed to decreases in natural gas prices) and keep-whole and wellhead purchase contracts (where we are exposed to increases in natural gas prices) helps to mitigate our exposure to changes in natural gas prices. Our hedging program is designed to adequately plan for cash
18
needed for debt service, capital expenditures and tax distributions. However, we do not currently anticipate using cash flow hedges in 2005 because management believes cash flows will be sufficient to fund the Company’s business.
Accounting Adjustments
Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amounts of approximately $223 million and $459 million, respectively, for the three and six months ended June 30, 2003. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations during the three and six months ended June 30, 2003. Management has concluded that these reclassifications are not material to the fair presentation of the Company’s financial statements.
Results of Operations
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
2003 | 2002 | 2003 | 2002 | |||||||||||||||
(in thousands) | ||||||||||||||||||
Operating revenues: | ||||||||||||||||||
Sales of natural gas and petroleum products | $ | 1,808,964 | $ | 1,234,435 | $ | 4,176,462 | $ | 2,252,599 | ||||||||||
Transportation, storage and processing | 67,406 | 62,978 | 127,931 | 120,274 | ||||||||||||||
Trading and marketing net margin | 1,403 | 3,519 | (32,791 | ) | 10,828 | |||||||||||||
Total operating revenues | 1,877,773 | 1,300,932 | 4,271,602 | 2,383,701 | ||||||||||||||
Purchases of natural gas and petroleum products | 1,562,619 | 1,067,999 | 3,654,662 | 1,907,645 | ||||||||||||||
Gross margin (1) | 315,154 | 232,933 | 616,940 | 476,056 | ||||||||||||||
Cost and expenses | 231,120 | 215,875 | 452,637 | 436,314 | ||||||||||||||
Equity in earnings of unconsolidated affiliates | 11,816 | 7,836 | 23,870 | 13,906 | ||||||||||||||
Gain (loss) from discontinued operations | 28,709 | (630 | ) | 32,357 | (774 | ) | ||||||||||||
Cumulative effect of changes in accounting principles | — | — | (22,802 | ) | — | |||||||||||||
EBIT (2) | 124,559 | 24,264 | 197,728 | 52,874 | ||||||||||||||
Interest expense, net | 41,759 | 42,295 | 84,497 | 85,604 | ||||||||||||||
Income tax expense | 281 | 3,313 | 2,052 | 5,614 | ||||||||||||||
Net income (loss) | $ | 82,519 | $ | (21,344 | ) | $ | 111,179 | $ | (38,344 | ) | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||||||
(millions) | (millions) | |||||||||||||||
Operating revenues: | ||||||||||||||||
Natural gas segment | $ | 2,177 | $ | 1,872 | $ | 4,381 | $ | 4,250 | ||||||||
NGL segment | 482 | 450 | 1,060 | 951 | ||||||||||||
Intersegment eliminations | (277 | ) | (266 | ) | (657 | ) | (578 | ) | ||||||||
Total operating revenues | 2,382 | 2,056 | 4,784 | 4,623 | ||||||||||||
Purchases of natural gas and petroleum products | 2,002 | 1,746 | 4,039 | 4,017 | ||||||||||||
Gross margin (a) | 380 | 310 | 745 | 606 | ||||||||||||
Costs and expenses | 223 | 229 | 433 | 447 | ||||||||||||
Equity in earnings of unconsolidated affiliates | 14 | 12 | 31 | 24 | ||||||||||||
EBIT from continuing operations before Cumulative effect of accounting change (b) | 171 | 93 | 343 | 183 | ||||||||||||
Interest expense, net | 39 | 42 | 79 | 84 | ||||||||||||
Income tax expense | 2 | — | 5 | 2 | ||||||||||||
Income from discontinued operations | — | 31 | 5 | 37 | ||||||||||||
Cumulative effect of change in accounting principles | — | — | — | (23 | ) | |||||||||||
Net income | $ | 130 | $ | 82 | $ | 264 | $ | 111 | ||||||||
Gross margin consists of total operating | ||
(b) | EBIT consists of net income from continuing operations before cumulative effect of accounting change, net interest expense and income tax expense. EBIT is a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of operations without regard to financing methods or capital structure. As an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. |
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Three months ended June 30, 20032004 compared with three months ended June 30, 20022003
Operating Revenues —–Total operating revenues increased $576.9$326 million, or 44%16%, to $1,877.8$2,382 million in the second quarter of 20032004 from $1,300.9$2,056 million in 2002. Of thisthe same period of 2003. This increase approximately $574.6was primarily due to the following factors:
Purchases of Natural Gas and Petroleum Products —– Purchases of natural gas and petroleum products increased $494.6$256 million, or 46%15%, to $1,562.6$2,002 million in the second quarter of 20032004 from $1,068.0$1,746 million in 2002. Purchases increased by approximately $520.6 millionthe same period of 2003. The increase was primarily due to the following factors:
Three Months Ended June 30, | ||||||||
2004 | 2003 | |||||||
(millions) | ||||||||
Gross Margin: | ||||||||
Natural gas segment | $ | 368 | $ | 302 | ||||
NGL segment | 12 | 8 | ||||||
Total gross margin | $ | 380 | $ | 310 | ||||
Gross Margin —GrossTotal gross margin increased $82.3$70 million, or 35%,23% to $315.2$380 million in the second quarter of 20032004 from $232.9$310 million in 2002. Of this increase, approximately $59 million (net of hedging) was the result of a $.12 per gallon increase in average NGLs prices. This increase was offset by an approximately $28 million decrease in gross margin due to a $2.01 per million British thermal units (“Btus”) increase in natural gas prices. During the second quarter of 2003, we elected to reduce levels of keep-whole processing activities from time to time due to
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less profitable processing margins. These elections increased gross margin by approximately $20 million and are not reflected in the above pricing impacts. Average prices in the second quarter of 2003 were $.49 per gallon for NGLs and $5.41 per million Btus for natural gas as compared with $.37 per gallon for NGLs and $3.40 per million Btus for natural gas during the same period in 2002. Partially offsetting the increase in gross margin was a $2.1 million decrease in trading and marketing net margin. Other increases of approximately $3 million relate to our natural gas marketing based trading activity as discussed below.
Other increases in gross margin of approximately $32 million resulted from non-recurring charges during the second quarter of 2002 for reserves for gas imbalances with suppliers and customers of $12 million, storage inventory writedown of $6 million and miscellaneous other charges including items related to resolution of disputed receivables and payables of $14 million.2003.
Gross margin associated with the Natural Gas Segment increased $86.6$66 million, or 39%22%, to $308.9$368 million in the second quarter of 2004 from $222.3$302 million in the same period of 2003, mainly as a result of higherthe following factors:
Gross margin associated with our electionthe NGL Segment increased $4 million, or 50% to reduce levels of keep-whole processing activities offset by$12 million in the increasesecond quarter 2004 from $8 million for the same period in average natural gas prices. Also contributing to this2003. This increase was a $0.4 millioncomprised primarily of an increase in trading and marketing net margin, associated with derivative settlementswholesale propane marketing and markedNGL pipelines.
NGL production during the second quarter 2004 increased 19,000 barrels per day, or 5%, to market valuations371,000 barrels per day from 352,000 barrels per day in the same period of unsettled contracts related to our2003, and natural gas trading and marketing activities. Natural gas trading and marketing net margin excludes approximately $3 million of increases in gross margin realizedtransported and/or processed during the second quarter of 2003 on our physical natural gas asset based marketing activity which, prior2004 decreased 0.1 trillion Btus per day, or 1%, to January 1, 2003, was recorded in trading and marketing net margin. As a result7.5 trillion Btus per day from 7.6 trillion Btus per day during the same period of 2003. The primary cause of the rescission of EITF 98-10, this activity is now presented on a gross basisincrease in gas sales and purchases (see Note 2 to Consolidated Financial Statements). Gross marginNGL production was processing elections associated with this segment was also positively affected bypoor processing economics on keep-whole volumes in 2003 and the second quarteracquisition of 2002 charges totaling $32 million related to reserves for gas imbalances with suppliers and customers, a writedown of storage inventory and charges related to completion of our account reconciliation project as discussed above.
Gross margin associated with the NGLs Segment decreased $4.4 million, or 42% to $6.2 millionprocessing assets in Southeast New Mexico in the second quarter of 2003 from $10.6 million in the same period of 2002. This decrease was primarily the result of a $2.6 million decrease in trading and marketing net margin.2004.
Costs and Expenses —Operating and maintenance expenses increased $8.9decreased $6 million, or 8%5%, to $114.6$107 million in the second quarter of 20032004 from $105.7$113 million in the same period of 2002. Contributing to this increase were increased expenditures for facility maintenance and pipeline repair of $4 million, environmental compliance of $2 million, and accretion expense associated with SFAS No. 143 implementation (see Notes 2 and 4 to Consolidated Financial Statements) of $1 million. General and administrative expenses increased $1.2 million, or 3%, to $40.3 million in the first quarter of 2003, from $39.1 million in the same period of 2002.
Depreciation and amortization expenses increased $7.1 million, or 10%, to $76.3 million in the second quarter of 2003 from $69.2 million in the same period of 2002. This increase was due primarily to ongoing capital expenditures for well connections, facility maintenance and enhancements, and the implementation of SFAS No. 143.
Other costs and expenses decreased $2.0 million to a gain of $0.1 million in the second quarter of 2003 from a $1.9 million charge in the second quarter of 2002.2003. This decrease iswas primarily due primarily to the $1.9following factors:
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unconsolidated affiliate as required by FIN 46R (see Note 2 to the Consolidated Financial Statements). Certain operating costs paid by us to this affiliate are now eliminated in consolidation of this affiliate; and |
Equity in Earnings of Unconsolidated Affiliates —Equity in earnings of unconsolidated affiliates increased $4.0 million, or 51%, to $11.8 million in the second quarter of 2003 from $7.8 million in the second quarter of 2002. This increase is primarily the result of increased earnings from the 2002 acquisition of an interest in the Discovery Pipeline located in offshore Gulf of Mexico of $1.5 million, our general partnership interest in TEPPCO Partners, L.P. (“TEPPCO”) of $0.8 million and other equity investments.
Interest Expense, net —Interest expense, net, decreased $0.5$3 million, or 1%7% to $41.8$39 million in the second quarter of 20032004 from $42.3$42 million in the same period of 2002.2003. This decrease was primarily the result of lower interest expense due to lower outstanding debt levels and an increase in interest income from higher cash investments which reduced interest expense in the second quarter of 2004 compared with the second quarter of 2003.
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Income Taxes —We are structured as a limited liability company, which is a pass-through entity for U.SUnited States income tax purposes. Income tax expense decreased $3.0 million to $0.3of $2 million in the second quarter of 2003 from $3.3 million in the same period of 2002 due primarily2004 is attributable to lower earnings associated with tax-paying subsidiaries.
Gain (Loss) FromIncome from Discontinued Operations — Gain (Loss)– Income from discontinued operations increased $29.3 million, to $28.7was $31 million in the second quarter of 20032003. Income from a loss of $0.6 million in the second quarter of 2002. This increase is primarily the result of the gaindiscontinued operations includes gains on the sale of various natural gas gatheringdiscontinued operations and processing assetsthe results of such operations (see Note 113 to the Consolidated Financial Statements).
Six months ended June 30, 20032004 compared with six months ended June 30, 20022003
Operating Revenues —–Total operating revenues increased $1,887.9$161 million, or 79%3%, to $4,271.6$4,784 million in the first six months of 20032004 from $2,383.7$4,623 million in 2002. Of thisthe same period of 2003. This increase approximately $1,923.9was primarily due to the following factors:
Purchases of Natural Gas and Petroleum Products —– Purchases of natural gas and petroleum products increased $1,747.1$22 million, or 92%1%, to $3,654.7 million in the second quarter of 2003 from $1,907.6 million in 2002. Purchases increased by approximately $1,773.1 million primarily due to higher commodity prices. This increase was offset by approximately $26 million of non-recurring charges from the second quarter of 2002 as discussed below.
Gross Margin —Gross margin increased $140.8 million or 30%, to $616.9$4,039 million in the first six months of 20032004 from $476.1$4,017 million in 2002. Of thisthe same period of 2003. This increase approximately $196was primarily due to the following factors:
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Six Months Ended June 30, | ||||||||
2004 | 2003 | |||||||
(millions) | ||||||||
Gross Margin: | ||||||||
Natural gas segment | $ | 713 | $ | 581 | ||||
NGL segment | 32 | 25 | ||||||
�� | ||||||||
Total gross margin | $ | 745 | $ | 606 | ||||
Gross Margin —Total Gross margin increased $139 million, or 23% to time due to less profitable processing margins. These elections increased gross margin by approximately $26$745 million and are not reflected in the above pricing impacts. Average prices in the first six months of 2003 were $.54 per gallon for NGLs and $6.00 per2004 from $606 million Btus for natural gas as compared with $.34 per gallon for NGLs and $2.86 per million Btus for natural gas duringin the same period in 2002. Partially offsetting the increase in gross margin was a $43.6 million decrease in trading and marketing net margin. Other increases of approximately $23 million relate to our natural gas asset based marketing activity as discussed below.
Other increases in gross margin of approximately $32 million resulted from non-recurring charges during the first six months of 2002 for reserves for gas imbalances with suppliers and customers of $12 million, storage inventory writedown of $6 million and miscellaneous other charges including items related to resolution of disputed receivables and payables of $14 million.2003.
Gross margin associated with the Natural Gas Segment increased $143.4$132 million, or 32%23%, to $592.8 million from $449.4 million, mainly as a result of higher commodity prices. Commodity sensitive processing arrangements accounted for approximately $126 million (net of hedging) of this increase due mainly to the increase in average NGLs prices along with our election to reduce levels of keep-whole processing activities offset by the increase in average natural gas prices. Offsetting this increase was a $32.4 million decrease in trading and marketing net margin associated with derivative settlements and marked to market valuations of unsettled contracts related to our gas trading and marketing activities. Natural gas trading and marketing net margin excludes approximately $23 million of increases in gross margin realized during the first six months of 2003 on our physical natural gas asset based marketing activity which, prior to January 1, 2003, was recorded in trading and marketing net margin. As a result of the rescission of EITF 98-10, this activity is now presented on a gross basis in gas sales and purchases (see Note 2 to Consolidated Financial Statements). Gross margin associated with this segment was also positively affected by the second quarter of 2002 charges totaling $32 million related to reserves for gas imbalances with suppliers and customers, a writedown of storage inventory and charges related to completion of our account reconciliation project as discussed above.
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Gross margin associated with the NGLs Segment decreased $2.5 million, or 9% to $24.2$713 million in the first six months of 20032004 from $26.7$581 million in the same period of 2002.2003, mainly as a result of the following factors:
Gross margin associated with the NGL Segment increased $7 million, or 28% to $32 million in the first six months of 2004 from $25 million for the same period in 2003. This decreaseincrease was comprised primarily of an $11.2 million decreaseincrease in trading and marketing net margin offset by increasesmargin.
NGL production during the first six months of 2004 increased 4,000 barrels per day, or 1%, to 364,000 barrels per day from 360,000 barrels per day in northeast wholesale propane marketingthe same period of 2003, and terminals marginnatural gas transported and/or processed during the first six months of $1 million, a $1 million increase in margin relating2004 decreased 0.2 trillion Btus per day, or 3%, to 7.4 trillion Btus per day from 7.6 trillion Btus per day during the salesame period of inventory resulting from renegotiation of certain pipeline operating agreements, a $1 million increase from the operation of a newly constructed pipeline in south Texas and higher margins from other NGLs assets.2003.
Costs and Expenses —Operating and maintenance expenses increased $21.6decreased $17 million, or 11%8%, (excluding $11 million in first six months 2002 accounting adjustments – see Note 9 to Consolidated Financial Statements) to $221.0$201 million in the first six months of 20032004 from $199.4$218 million in the same period of 2002. Contributing2003. This decrease was primarily due to the following factors:
Depreciation and amortization expenses increased $11.5 million, or 8%, to $152.1 million in the first six months of 2003 from $140.6 million in the same period of 2002. This increase was due primarily to ongoing capital expenditures for well connections, facility maintenance and enhancements, and the implementation of SFAS No. 143.
Other costs and expenses decreased $7.3 million to a gain of $0.2 million in the first six months of 2003 from a $7.1 million charge in the first six months of 2002. This decrease is due primarily to the first six months 2002 accounting adjustment of $5.3 million for the recognition of a loss on the sale of assets associated with a partnership investment (see Note 9 to Consolidated Financial Statements), and the $1.9 million impairment of investments in offshore Gulf of Mexico partnerships.
Equity in Earnings of Unconsolidated Affiliates —Equity in earnings of unconsolidated affiliates increased $10.0 million, or 72%, to $23.9 million in the first six months of 2003 from $13.9 million in the first six months of 2002. This increase is primarily the result of increased earnings from our general partnership interest in TEPPCO of $4.6 million and increased earnings from the 2002 acquisition of an interest in the Discovery Pipeline located in offshore Gulf of Mexico of $4.3 million, and other equity investments.
Interest Expense, net —Interest expense, net, decreased $1.1$5 million, or 1%,6% to $84.5$79 million in the first six months of 20032004 from $85.6$84 million in the same period of 2002.2003. This decrease was primarily the result of lower interest expense due to lower outstanding debt levels and an increase in interest income from higher cash investments which reduced interest expense in the first six months of 2004 compared with first six months of 2003.
Income Taxes —We are structured as a limited liability company, which is a pass-through entity for U.SUnited States income tax purposes. Income tax expense decreased $3.5 million to $2.1of $5 million in the first six months of 2003 from $5.6 million in the same period of 2002 due primarily2004 is attributable to lower earnings associated with tax-paying subsidiaries.
Gain (Loss) FromIncome from Discontinued Operations — Gains– Income from discontinued operations increased $33.2 million, to a gain of $32.4was $5 million in the first six months of 2003 from a $0.82004 and $37 million loss in the first six months of 2002. This increase is primarily the result of the gain2003. Income from discontinued operations includes gains on the sale of various natural gas gatheringdiscontinued operations and processing assetsthe results of such operations in both periods presented (see Note 103 to the Consolidated Financial Statements).
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Cumulative Effect of ChangesChange in Accounting Principles —Cumulative effect of changeschange in accounting principles increased towas a loss of $22.8$23 million in the first six months of 2003 from no charge in the first six months of 2002.2003. Of this amount, $17.4$18 million relates to the implementation of SFAS No. 143, and $5.4$5 million is due to the rescission of EITF 98-10 (see Note 2 to Consolidated Financial Statements).
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Liquidity and Capital Resources
As of June 30, 2003,2004, we had $153.0$253 million in cash and cash equivalents compared to $24.8$43 million as of December 31, 2002. Our working capital was a $8.7 million deficit2003. Included in cash and cash equivalents as of June 30, 2003, compared to a $306.22004 was approximately $28 million deficit as ofheld by our Canadian subsidiaries for their operations. The remaining cash balance was primarily available for general corporate purposes. Current assets exceeded current liabilities by $135 million at June 30, 2004 and current liabilities exceeded current assets by $73 million at December 31, 2002.2003. We rely upon cash flows from operations and borrowings to fund our liquidity and capital requirements. A material adverse change in operations or available financing may impact our ability to fund our currentrequirements for liquidity and capital resource requirements.resources.
Operating Cash Flows
During the first six months of 2003, funds of $199.4 million were2004, cash provided by operating activities a decreasewas $427 million, an increase of $31.3$206 million from $230.7$221 million in the first six months of 2002.2003. This increase was due primarily to a $153 million increase in net income. The decreaseincrease in net income is primarily due largely to the favorable effects of commodity prices, net of hedging, improved results from trading and marketing activities, and decreased operating expenses, partially offset by lower volumes. Additional increases were the result of changes in working capital balances and unrealized mark-to-market and hedging activity offsetactivity.
Cash distributions received from unconsolidated affiliates were $38 million in the first six months of 2004 and $31 million in the first six months of 2003. These distributions were in excess of earnings from unconsolidated affiliates by an increase$7 million in net income.each period.
Price volatilityVolatility in crude oil, NGLsNGL and natural gas prices hasand the structure of our commodity supply contracts have a direct impact on our generation and use of cash from operations due to its impact on net income as described in the Effects of Commodity Prices section above, along with the resulting changes in working capital.
Investing Cash Flows
During the first six months of 2003, funds2004, cash used in investing activities was $62 million, a decrease of $55.1$90 million werefrom cash provided by investing activities an increase of $189.8$28 million from $134.7 million of funds used in investing activities during the first six months of 2002. The increase is partially related to proceeds of $90.2 million from sales of discontinued operations.2003. Our capital expenditures consist of expenditures for construction and acquisition of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities and acquisitions.facilities. For the first six months of 2003,2004, we spent approximately $67.7$132 million on capital expenditures offor continuing operations compared to $165.2$66 million in the first six months of 2002.2003. The increase is due to the acquisition of gathering, processing and transmission assets in Southeast New Mexico, partially offset by reduced well connections and plant upgrades in the first six months of 2004, as compared to the same period in 2003. The cash used for capital expenditures is partially offset by proceeds of $62 million from the sale of discontinued operations.
Our level of capital expenditures for acquisitions and construction and other investments 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,asset sales, our credit facilitiesfacility or other available sources of financing. Our capital expenditures forecast for the year ending December 31, 2004 is approximately $220 million. Depending on cash flow results, redeployment of capital from divestitures and opportunities in the marketplace, 2004 acquisition and capital expenditures may vary from the forecast.
Investments in unconsolidated affiliates provided $31.1 million in cash distributions to us during the first six months of 2003 compared with $24.0 million during the first six months of 2002.23
Financing Cash Flows
Bank Financing and Commercial Paper
On March 28, 2003,26, 2004, we entered into a new credit facility (the “Facility”). The Facility replaces thea credit facility that matured on March 28, 2003.26, 2004. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 26, 2004,25, 2005; however; any outstanding loansborrowings under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility is a $350.0$250 million revolving credit facility, all of which $100.0 million can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA is defined by the Facility to be earnings before interest, taxes and depreciation and amortization and other adjustments); and contains various restrictions applicable to dividends and other payments to our members.. The Facility bears interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 1.25%1.125% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.25%0.125% per year and (b) the Federal Funds rate plus 0.75%0.625% per year. At June 30, 2003,2004, there were no borrowings or letters of credit drawn against the Facility.
On March 28,November 3, 2003, we also entered intoexecuted a $100.0$32 million funded short-term loanirrevocable standby letter of credit, to be used to secure transaction exposure with a bank (the “Short-Term Loan”). The Short-Term Loan is used for working capital and other general corporate purposes. The Short-Term Loan maturescounterparty, which expired on September 30, 2003, and may be repaid at any time. The Short-Term Loan has the same
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financial covenants as the Facility. The Short-Term Loan bears interest at a rate equal to, at our option, either (1) LIBOR plus 1.35% per year or (2) the higher of (a) the bank’s prime rate and (b) the Federal Funds rate plus 0.50% per year. Subsequent to June 30, 2003, we repaid this entire loan with funds generated from asset sales and operations.May 15, 2004.
At June 30, 2003,2004, we had no outstanding commercial paper. At no time has the amount of our outstanding commercial paper exceeded the available amount under the Facility. In the future, our debt 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$500 million. The shelf registration statement provides for the issuance of senior notes, subordinated notes and trust preferred securities.
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 andas supported by 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 or distributions that we may make. Our ability to meet current and anticipated operating requirements will depend on our future performance.
Distributions
We are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. Our Limited Liability Company Agreement provides for taxable income to be allocated in accordance with the Internal Revenue Code Section 704(c). This Code section takes into account the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The required distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the six months ended June 30, 2004, we paid distributions of $11 million based on estimated annual taxable income allocated to the members according to their respective ownership percentages. As of June 30, 2004, additional distributions payable of $5 million were included in Other current liabilities in the Consolidated Balance Sheets.
In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to our members. Our board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. Our LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members. During the six months ended June 30, 2004, with the approval of both members, we paid total dividends of $137 million to the members, allocated in accordance with their respective ownership percentages.
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Contractual Obligations, and Commercial Commitments and Off-Balance Sheet Arrangements
As part of our normal business, we are a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included onin the Consolidated Balance Sheets. The possibility of us having to honor our contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We will record a reservereserves if events occur requiringthat require that one to be established.
At June 30, 2003,January 1, 2004, we were the guarantor of approximately $94.1$3 million of debt associated with nonconsolidated entities, of which $84.6 million related to our 33.33% ownership interest in Discovery Producer Services, LLC, (“Discovery”) and $9.5 million is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (“GGG”). The guaranteed debt related to Discovery is due December 31, 2003, and is expected to be refinanced. The guaranteed debt related to GGG is scheduled to be repaid in full by January 31, 2004. In the event that the unconsolidated subsidiaries default on the debt payments, we would be required to pay the debt.for an affiliate. Assets of the unconsolidated subsidiaries arewere pledged as collateral for the debt. This debt was repaid in January 2004.
At June 30, 2003,2004, we had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.
We periodically enter intohave various indemnification agreements for the acquisition or divestiture of assets.outstanding contained in asset purchase and sale agreements. These indemnification agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities relatedgenerally relate to the assets being acquiredchange in environmental and tax laws or divested. Typically, claims may be made by third parties under thesesettlement of outstanding litigation. These indemnification agreements for various periods of time depending on the nature of the claim. The survival periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can range depending on the nature of the claim and the particular transaction. We are unable tocannot estimate the total maximum potential amount of future payments under these indemnification agreements due to several factors, including uncertainty asthe uncertainties related to whether claims will be made under these indemnities.changes in laws and regulation with regard to taxes, safety and protection of the environment or the settlement of outstanding litigation, which are outside our control. At June 30, 2003,2004, we had an approximate $1.5a liability of $1 million liability recorded for theseknown liabilities related to outstanding indemnification provisions.
For an in-depth discussion of our contractual obligations and commercial commitments, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in our Form 10-K for December 31, 2003.
New Accounting Standards
In May 2003, the FASB issued SFAS No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in statements of financial positionthe consolidated balance sheets and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS No. 150 also requires disclosures about the nature and terms of the financial
23
instruments and about alternative ways of settling the instruments. The provisions of SFAS No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, we will reclassify ourreclassified preferred members’ interest, which are mandatorily redeemable, of $200 million from mezzanine equity to long-term liabilities at its fair value of approximately $200 million. Future disbursementslong term debt and prospectively classified accrued or paid distributions on these securities, which had previously been classified as dividends, on these preferred members’ interest will be classified as interest expense.
In April During 2003, we redeemed the FASB issued SFAS No. 149, “Amendmentremaining $200 million of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embeddedthese securities in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component, and amends the definition of an underlying to conform it to language used in FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, SFAS No. 149 also incorporates certain of the Derivative Implementation Group Implementation Issues. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The guidance is to be applied to hedging relationships on a prospective basis. We do not anticipate SFAS No. 149 will have a material impact on our consolidated results of operations, cash flows or financial position.cash.
In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46Entities” which requires an entity to consolidate a variable interest entity if it is the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity’s activities. The primary beneficiary isentity. We adopted the party that absorbs a majorityprovisions of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, and its related interpretations (“FIN 46 is required to be applied46R”) in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively withquarter of 2004. As a cumulative-effect adjustmentresult, we consolidated one entity, previously accounted for under the equity method of accounting, on January 1, 2004. This entity, which is a substantive entity, had total assets of approximately $92 million as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. We have not identified any variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and continue to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. It is reasonably possible that we will disclose information about variable interest entities upon the application1, 2004. Adoption of FIN 46, primarily as the result of investments we has in certain unconsolidated affiliates. For all of these unconsolidated affiliates, we believe that our maximum exposure to loss would be equal to our investment in these entities, plus our potential obligations under our guarantees of unconsolidated debt. At June 30, 2003, our total investment in, plus the value of any guaranteed debt for entities that have a reasonable possibility to be determined to be variable interest entities, was approximately $160.7 million. We continue to assess FIN 46 but do not anticipate that it will have a material impact on our consolidated results of operations, cash flows or financial position.
In November 2002, the FASB issued Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We adopted the initial recognition and measurement provisions of FIN 45 effective January 1, 2003. Adoption of the new interpretation46R had no material effect on our consolidated results of operations, cash flows or financial position.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” We adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost would have been recognized at the date of an entity’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and
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recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.
In June 2002,July 2003, the EITF reached a partial consensus onin EITF Issue No. 02-03, “Issues Involved in03-11 (“EITF 03-11”), “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative ContractsInstruments and Hedging Activities, and Not Held for Trading Purposes, and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that effective for periods ending after July 15, 2002, mark-to-marketdetermining whether realized gains and losses on energy tradingderivative contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. We had previously chosen to report certain of our energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice.
In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, must now be recorded at the lower of cost or market and are reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market via a cumulative-effect adjustment of $5.4 million as a reduction to 2003 earnings. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.
In October 2002, the EITF also reached a consensus on Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shownreported on a net or gross basis inis a matter of judgment that depends on the income statement. Gainsrelevant facts and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection withcircumstances. In analyzing the guidance in Issue No.facts and circumstances, EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.Agent” and Opinion No. 29, “Accounting for Nonmonetary Transactions,” Upon applicationshould be considered. EITF 03-11 is effective for transactions or arrangements entered into after September 30, 2003. The adoption of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under Issue No. 98-10. Accordingly, for the three and six months ended June 30, 2003, derivative instruments that are held for trading and marketing purposes and are accounted for under mark-to-market accounting are included in Trading and Marketing Net MarginEITF 03-11 had no material effect on the Consolidated StatementsCompany’s consolidated results of Operations. For the three and six months ended June 30, 2002, Trading and Marketing Net Margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales) that no longer qualify for net presentation after the rescission of Issue No. 98-10. The new gross versus net revenue presentation requirements had no impact on operating incomeoperations, cash flows or net income.financial position.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, we recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.25
In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or
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includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. We are currently assessing the impactThe adoption of EITF Issue No. 01-08 will havehad no material effect on our consolidated results of operations, cash flows or financial position.
Cumulative Effect of Accounting Change— We adopted the provisions of EITF 02-03 that required new non-derivative energy trading contracts entered into after October 25, 2002 to be accounted for under the accrual accounting basis. Non-derivative energy trading contracts recorded in the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values were adjusted to historical cost via a cumulative effect adjustment of $5 million as a reduction to earnings in the first six months of 2003.
We adopted the provisions of SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations,” as of January 1, 2003 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In accordance with the transition provisions of SFAS 143, we recorded a cumulative effect adjustment of $18 million as a reduction to earnings in the first six months of 2003.
Subsequent EventsAcquisitions and Dispositions
In July 2003, we entered into an agreement to sell approximately 900 vehicles for approximately $14 million. This is a sale-leaseback transaction whereby we sold the vehicles but will lease them back over a one year lease term. The lease expires in JulyFebruary 2004, with annual extensions exercisable at our option. The future minimum lease payments under the lease are approximately $15 million. We do not have an option to purchase the leased vehicles at the end of the minimum lease term. As the proceeds from the sale of the vehicles are equal to the net book value of the vehicles, no gain or loss has been recognized.
In August 2003, we entered into a purchase and sale agreement to sell certain gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, plus or minus various adjustments that will be made at closing. We anticipate closingmillion. The transaction closed in the transaction on September 30, 2003first quarter of 2004 with no significant book gain or loss.
For information on subsequent events On March 10, 2004, we entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips, a related to financing matters, seeparty, for a total purchase price of approximately $80 million, consisting of $74 million in cash and the Financing Cash Flows section above.assumption of approximately $6 million of liabilities. The transaction closed during the second quarter of 2004.
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Item 3. Quantitative and Qualitative Disclosure about Market Risks
Risk and Accounting Policies
We are exposed to market risks associated with commodity prices, counterparty credit, exposure, interest rates, and, to a limited extent, foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. OurDuke Energy Field Services’ Risk Management Committee (“Risk Management Committee”) is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Risk Management Committee is composed of senior executives who receive regular briefings on ourthe Company’s positions and exposures as well as periodic updates from and consultations with the Duke Energy Chief Risk Officer (“CRO”)(CRO) and other expert resources at Duke Energy regarding market risk positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, and various other risks, including monitoring exposure limits.
Commodity Price Risk
We are exposed to the impact of market fluctuations primarily in the price of natural gas and NGLsNGL 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, futures and options for non-trading activity (primarily hedge strategies). Seeoptions. (See Notes 2 and 34 to the Consolidated Financial Statements.)
Commodity Derivatives — Trading and Marketing—The risk in the commodity trading and marketing portfolios is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily EarningsValue at Risk (“DER”DVaR”) as described below. DERDVaR is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading and marketing portfolios (which includes all trading and marketing 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.
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DERDVaR computations are based on a historical simulation, which uses price movements over an 11 day period 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,NGL, natural gas and other energy-related products. DERDVaR computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Our DERDVaR amounts for commodity derivativesderivative instruments held for trading and marketing purposes are shown in the following table.table:
Daily EarningsValue at Risk (in thousands)
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 | |||||||||||||
June 30, 2003 | June 30, 2002 | June 30, 2003 | June 30, 2003 | |||||||||||||
Calculated DER | $ | 774 | $ | 2,488 | $ | 2,260 | $ | 363 |
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 | |||||||||||||
June 30, 2004 | June 30, 2003 | June 30, 2004 | June 30, 2004 | |||||||||||||
Calculated DVaR | $ | 1 | $ | 2 | $ | 1 | — | |||||||||
Daily EarningsValue at Risk (in thousands)
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 six | for the six | |||||||||||||
six months ended | six months ended | months ended | months ended | |||||||||||||
June 30, 2003 | June 30, 2002 | June 30, 2003 | June 30, 2003 | |||||||||||||
Calculated DER | $ | 1,294 | $ | 2,387 | $ | 6,692 | $ | 363 |
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 six | for the six | |||||||||||||
six months ended | six months ended | months ended | months ended | |||||||||||||
June 30, 2004 | June 30, 2003 | June 30, 2004 | June 30, 2004 | |||||||||||||
Calculated DVaR | $ | 1 | $ | 2 | $ | 3 | — | |||||||||
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DVaR is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DERDVaR also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DERDVaR may understate or overstate actual results. DERDVaR is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading and marketing activity, it may not accurately estimate risk due to limited price information. Stress tests may be employed in addition to DERDVaR to measure risk where market data information is limited. In the current DERDVaR methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.
Our exposure to commodity price risk is influenced by a number of factors, including contract size, length of contract, market liquidity, location and unique or specific contract terms. The unrealizedEffective January 1, 2003, in connection with the implementation of EITF 02-03, the Company designates each commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or sale contract, while certain non-trading derivatives, which are related to our asset based marketing, are non-trading mark-to-market derivatives. For each of the Company’s derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations are as follows:
Classification of Contract | Accounting Method | Presentation of Gains & Losses or Revenue & Expense | ||
Trading Derivatives | Mark-to-marketa | Net basis in Trading and marketing net margin | ||
Non-Trading Derivatives: | ||||
Cash Flow Hedge | Hedge methodb | Gross basis in the same income statement category as the related hedged item | ||
Fair Value Hedge | Hedge methodb | Gross basis in the same income statement category as the related hedged item | ||
Normal Purchase or Normal Sale | Accrual methodc | Gross basis upon settlement in the corresponding income statement category based on commodity type | ||
Non-Trading Mark-to- Market | Mark-to-marketa | Net basis in Trading and marketing net margin |
a Mark-to-market- An accounting method whereby the change in the fair value of tradingthe asset or liability is recognized in the Consolidated Statements of Operations in Trading and marketing instruments outstanding at June 30, 2003net margin during the current period.
b Hedge method- An accounting method whereby the change in the fair value of the asset or liability is recorded in the Consolidated Balance Sheets and December 31, 2002 wasthere is no recognition in the Consolidated Statements of Operations for the effective portion until the hedged transaction occurs.
c Accrual method- An accounting method whereby there is no recognition in the Consolidated Statements of Operations for changes in fair value of a gaincontract until the service is provided or the associated delivery of $3.7 million and a loss of $28.0 million, respectively.product occurs.
The fair value of theseour mark-to-market 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.
When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading and marketing contracts may not be readily determinable because the duration of the contracts exceedscould exceed the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates, and tenor. Of these components, volatility and correlation are the most subjective. Internally developed valuation techniques include the use of interpolation, extrapolation, and fundamental analysis in the calculation of a contract’s fair value. All risk components for new and existing transactions are valued using the same valuation technique and market data and discounted using a LIBOR based interest rate. Valuation adjustments for performance, and market risk and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Operations.
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The following table shows the fair value of our mark-to-market trading and marketing portfoliosportfolio as of June 30, 2003.
Fair Value of Contracts as of June 30, 2003 (in thousands) | ||||||||||||||||||||
Maturity in | ||||||||||||||||||||
Maturity in | Maturity in | Maturity in | 2006 and | Total Fair | ||||||||||||||||
Sources of Fair Value | 2003 | 2004 | 2005 | Thereafter | Value | |||||||||||||||
Prices supported by quoted market prices and other external sources | $ | (472 | ) | $ | (1,251 | ) | $ | 1,854 | $ | (234 | ) | $ | (103 | ) | ||||||
Prices based on models and other valuation methods | 1,661 | 6,635 | (737 | ) | (3,790 | ) | 3,769 | |||||||||||||
Total | $ | 1,189 | $ | 5,384 | $ | 1,117 | $ | (4,024 | ) | $ | 3,666 | |||||||||
Fair Value of Mark-to-Market Contracts as of June 30, 2004 (millions) | ||||||||||||||||||||
Maturity in | Maturity in | Maturity in | Maturity in 2007 | Total | ||||||||||||||||
Sources of Fair Value | 2004 | 2005 | 2006 | and Thereafter | Fair Value | |||||||||||||||
Trading: | ||||||||||||||||||||
Prices supported by quoted market prices and other external sources | $ | 11 | $ | 6 | $ | (2 | ) | $ | — | $ | 15 | |||||||||
Prices based on models and other valuation methods | — | — | — | (2 | ) | (2 | ) | |||||||||||||
Total Trading | 11 | 6 | (2 | ) | (2 | ) | 13 | |||||||||||||
Non-Trading: | ||||||||||||||||||||
Prices supported by quoted market prices and other external sources | (1 | ) | (3 | ) | — | — | (4 | ) | ||||||||||||
Prices based on models and other valuation methods | — | — | — | — | — | |||||||||||||||
Total Non-Trading | (1 | ) | (3 | ) | — | — | (4 | ) | ||||||||||||
Total Mark-to-Market | $ | 10 | $ | 3 | $ | (2 | ) | $ | (2 | ) | $ | 9 | ||||||||
The “Prices supported by quoted market prices and other external sources” category includes our 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 and (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.point. In certain instances structured transactions can be decomposed and modeled by us as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore has 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, may use various commodity instruments such as natural gas, crude oil and NGLsNGL contracts to hedge the value of our assets and operations from such price risks. In accordance with SFAS No. 133,Our hedging program has historically reduced the potential negative impact that commodity price changes could have on our earnings and has improved our ability to adequately plan for cash needed for debt service and
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capital expenditures. However, we do not currently anticipate using cash flow hedges in 2005 because management believes cash flows will be sufficient to fund the Company’s business.
Our primary use of hedging commodity derivatives ishas been to hedge the output and production of assets we physically own. Contract terms are up to three years, however, sinceSince these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets, owned by us,liabilities or firm commitments, 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 Accumulated Other Comprehensive Income Loss (“AOCI”) for cash flow hedges 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.commitments. Amounts deferred in AOCI 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 AOCI through the date of de-designation remain in AOCI 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 forWe have utilized derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be
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recognized into earnings. Contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. However, asnot only to hedge commodity exposures, but also to hedge interest rate exposures (as discussed in the Interest Rate Risk section on page 31). As mentioned previously, the effective portion of the gains and losses for theseany of our hedging contracts are not recognized in earnings until settlementthe contracts mature at their thenfuture market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlementcontract maturity for the effective portion of these hedges.
The fair value of our qualifying hedge positions at a point in time is not necessarily indicative of the results realized when such contracts settle.
Fair Value of Contracts as of June 30, 2003 (in thousands) | ||||||||||||||||||||
Maturity in | ||||||||||||||||||||
Maturity in | Maturity in | Maturity in | 2006 and | Total Fair | ||||||||||||||||
Sources of Fair Value | 2003 | 2004 | 2005 | Thereafter | Value | |||||||||||||||
Prices supported by quoted market prices and other external sources | $ | (46,083 | ) | $ | (2,333 | ) | $ | 4,731 | $ | — | $ | (43,685 | ) | |||||||
Prices based on models and other valuation methods | (528 | ) | (210 | ) | — | — | (738 | ) | ||||||||||||
Total | $ | (46,611 | ) | $ | (2,543 | ) | $ | 4,731 | $ | — | $ | (44,423 | ) | |||||||
Fair Value of Hedging Contracts as of June 30, 2004 (millions) | ||||||||||||||||||||
Maturity in | ||||||||||||||||||||
Maturity in | Maturity in | Maturity in | 2007 and | Total Fair | ||||||||||||||||
Sources of Fair Value | 2004 | 2005 | 2006 | Thereafter | Value | |||||||||||||||
Prices supported by quoted market prices and other external sources | $ | (12 | ) | $ | 5 | $ | 2 | $ | (6 | ) | $ | (11 | ) | |||||||
Prices based on models or other valuation techniques | — | — | — | — | — | |||||||||||||||
Total | $ | (12 | ) | $ | 5 | $ | 2 | $ | (6 | ) | $ | (11 | ) | |||||||
Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $.01$0.01 per gallon in the price of NGLsNGL and $.10$0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(25)$(19) million and $5$1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.
Credit Risk
Our principleprincipal customers in the Natural Gas Segment are large, natural gas marketing services and industrial end-users. In the NGLsNGL segment, our principleprincipal customers arerange from large multi-national petrochemical and refining companies to small regional propane distributors. Substantially all of our natural gas and NGLsNGL sales are made at index, market-based prices. Approximately 40% of our NGLsNGL production is committed to ConocoPhillips and Chevron Phillips Chemical LLC,ChevronPhillips; under aan existing 15-year contract with a primary term thatwhich expires on January 1,in 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. Where exposed to credit risk, we analyze 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
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corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. 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 corporateour credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. Substantially all other agreementsIn addition, the Company’s standard gas and NGL sales contracts contain adequate assurance provisions which would allow us, at our discretion,the Company to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment in a form satisfactory to us.the Company.
Despite the current credit environment in the energy sector, management believes that the credit risk management process described above is operating effectively. As of June 30, 2003,2004, we hadheld cash or letters of credit of $17.3$74 million to secure future performance by counterparties, and had deposited with counterparties $9.5$3 million of such collateral to secure our obligations to provide future services.services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclosed credit ratings impact the amounts of collateral requirements.
Generally speaking, all physical and financial derivative contracts are settled in cash at the expiration of the contract term.
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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 debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for our debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical averages. As of June 30, 2003,2004, the fair value of our interest rate swapswaps was an asset of $16.3$6 million.
As of June 30, 2003,2004, we had no outstanding commercial paper.
As a result of our debt and our interest rate swap,swaps, we are exposed to market risks related to changes in interest rates. In the future, we intend to manage our interest rate exposure using a mix of fixed and floating interest rate debt. An increase of 0.5% in interest rates would result in an increase in annual interest expense of approximately $1.8$2 million.
Foreign Currency Risk
Our primary foreign currency exchange rate exposure at June 30, 20032004 was the Canadian dollar. Foreign currency risk associated with this exposure was not significant.
Item 4.Controls and Procedures
Our management, including the Chief Financial Officer and the Chief Executive Officer, have evaluated the effectiveness of our disclosure controls and procedures as(as defined in Exchange Act Rule 13a-14Rules 13a-15(e) and 15d-15(e)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this quarterly report. Our disclosure controls and procedures are effective in ensuring that information required to be disclosed in our reports under the Exchange Act are accumulated and communicated to management, including the Chief Financial Officer and the Chief Executive Officer, as appropriate to allow timely decisions regarding required disclosure. There have been no significant changes in our internal controls over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
3031
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For information concerning litigation and other contingencies, see Part I. Item 1, Note 68 to the Consolidated Financial Statements, “Commitments and Contingent Liabilities,” of this report and Item 3, “Legal Proceedings,” included in our Form 10-K for December 31, 2002,2003, which are incorporated herein by reference.
Management believes that the resolution of the matters referred to above will not have a material adverse effect on the consolidated results of operations or financial position of the Company.
Item 6. Exhibits and Reports on Form 8-K
(a) | Exhibits |
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||
31.2 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of | |||
32.1 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||
32.2 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||
(b) | Reports on Form 8-K | |||||||
None. |
3132
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DUKE ENERGY FIELD SERVICES, LLC | ||
August | ||
/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) |
3233
EXHIBIT INDEX
No. | ||||
Description | ||||
31.1 | ||||
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||||
31.2 | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of | |||
32.1 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||
32.2 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |