-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, MJ4fjlbau8ilhZKpRfpuOP9bjKwK5KaqwBIqSm/T+xW26ob/HeAdbM96lXqpgzCu OBtAJc7v+3UX9PXjQkdt2g== 0000950168-97-003568.txt : 19971205 0000950168-97-003568.hdr.sgml : 19971205 ACCESSION NUMBER: 0000950168-97-003568 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19971204 ITEM INFORMATION: FILED AS OF DATE: 19971204 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: DUKE ENERGY CORP CENTRAL INDEX KEY: 0000030371 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 560205520 STATE OF INCORPORATION: NC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-04928 FILM NUMBER: 97732291 BUSINESS ADDRESS: STREET 1: 422 S CHURCH ST CITY: CHARLOTTE STATE: NC ZIP: 28242-0001 BUSINESS PHONE: 7045940887 MAIL ADDRESS: STREET 1: 422 S CHURCH ST CITY: CHARLOTTE STATE: NC ZIP: 28242 FORMER COMPANY: FORMER CONFORMED NAME: DUKE POWER CO /NC/ DATE OF NAME CHANGE: 19920703 8-K 1 DUKE ENERGY CORPORATION 8-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------- FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported): December 4, 1997 DUKE ENERGY CORPORATION (Exact name of Registrant as Specified in its Charter) NORTH CAROLINA 1-4928 56-0205520 (State or Other Jurisdiction of (Commission File Number) (IRS Employer Incorporation) Identification No.) 422 South Church Street Charlotte, NC 28202-1904 28202-1904 (Address of Principle Executive Offices) (Zip code) Registrant's telephone number, including area code: 704-594-0887. ITEM 7: FINANCIAL STATEMENTS AND EXHIBITS The following exhibits are additional information filed with the Securities and Exchange Commission pursuant to the Securities and Exchange Act of 1934. EXHIBIT NO. DESCRIPTION 23.1 Consent of Independent Auditors 99.1 The following audited consolidated Financial Statements and Notes of Duke Energy Corporation are included in this Form 8-K: Consolidated Statements of Income for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Balance Sheets as of December 31, 1996 and 1995 Consolidated Statements of Common Stockholders' Equity for the Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements Independent Auditors' Report 1 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 CORPORATION /s/ Richard J. Osborne ----------------------------- Richard J. Osborne Executive Vice President and Chief Financial Officer December 4, 1997 2 EXHIBIT INDEX EXHIBIT NO. DESCRIPTION 23.1 Consent of Independent Auditors 99.1 The following audited consolidated Financial Statements and Notes of Duke Energy Corporation are included in this Form 8-K: Consolidated Statements of Income for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Balance Sheets as of December 31, 1996 and 1995 Consolidated Statements of Common Stockholders' Equity for the Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements Independent Auditors' Report 3 EX-23 2 EXHIBIT 23.1 EXHIBIT 23.1 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in Registration Statement Nos. 33-19274, 33-50543, 33-50617, 333-02571, 333-14209 and 333-30263 of Duke Energy Corporation on Form S-3, Registration Statement Nos. 2-72172, 333-12093, 333-34655, 333-29587, 333-29585, 333-29563 of Duke Energy Corporation on Form S-8, Registration Statement No. 333-23227 of Duke Energy Corporation on Form S-4 and Registration Statement Nos. 333-40679, 333-40679-01 and 333-40679-02 of Duke Energy Corporation, Duke Energy Capital Trust I and Duke Energy Capital Trust II, respectively, on Form S-3 of our report dated December 3, 1997, appearing in this Form 8-K Current Report of Duke Energy Corporation dated December 4, 1997. DELOITTE & TOUCHE LLP Charlotte, North Carolina December 4, 1997 EX-99 3 EXHIBIT 99.1 DUKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME (In millions, except per share amounts)
YEAR ENDED DECEMBER 31 --------------------------------------------------------- 1996 1995 1994 ---------------- ---------------- ---------------- Operating Revenues Natural gas and petroleum products Sales of natural gas and petroleum products $ 5,848.0 $ 3,397.2 $ 3,044.0 Transportation and storage of natural gas 1,522.9 1,500.6 1,432.8 Electric Generation, transmission, and distribution 4,436.6 4,454.6 4,312.4 Trading and marketing of electricity 77.8 9.8 - Other 417.1 332.5 325.8 ---------------- ---------------- ---------------- Total operating revenues 12,302.4 9,694.7 9,115.0 ---------------- ---------------- ---------------- Operating Expenses Natural gas and petroleum products purchased 5,414.3 3,119.3 2,829.4 Fuel used in electric generation 758.5 744.2 705.0 Net interchange and purchased power 456.8 480.2 553.4 Other operation and maintenance 2,382.8 2,209.0 2,171.1 Depreciation and amortization 789.4 737.1 716.8 Property and other taxes 342.0 336.6 333.3 ---------------- ---------------- ---------------- Total operating expenses 10,143.8 7,626.4 7,309.0 ---------------- ---------------- ---------------- Operating Income 2,158.6 2,068.3 1,806.0 ---------------- ---------------- ---------------- Other Income and Expenses Deferred returns and allowance for funds used during construction 104.8 113.9 107.0 Other, net 30.8 8.3 (6.0) ---------------- ---------------- ---------------- Total other income and expenses 135.6 122.2 101.0 ---------------- ---------------- ---------------- Earnings Before Interest and Taxes 2,294.2 2,190.5 1,907.0 Interest Expense 499.2 508.2 484.5 Minority Interests 6.2 - - ---------------- ---------------- ---------------- Earnings Before Income Taxes 1,788.8 1,682.3 1,422.5 Income Taxes 697.8 664.2 558.4 ---------------- ---------------- ---------------- Income Before Extraordinary Charge 1,091.0 1,018.1 864.1 Extraordinary Charge (net of tax) 16.7 - - ---------------- ---------------- ---------------- Net Income 1,074.3 1,018.1 864.1 Dividends on Preferred and Preference Stock 44.2 48.9 49.7 ---------------- ---------------- ---------------- Earnings Available for Common Stockholders $ 1,030.1 $ 969.2 $ 814.4 ================ ================ ================ Common Stock Data Average shares outstanding 361.2 361.2 360.2 Earnings per share (before extraordinary charge) $ 2.90 $ 2.68 $ 2.26 Earnings per share $ 2.85 $ 2.68 $ 2.26 Dividends per share $ 1.57 $ 1.50 $ 1.44
See Notes to Consolidated Financial Statements 4 DUKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions)
YEAR ENDED DECEMBER 31 --------------------------------------------------------- 1996 1995 1994 ---------------- ---------------- ---------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 1,074.3 $ 1,018.1 $ 864.1 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 964.9 953.8 904.5 Deferred income taxes 74.7 115.2 209.0 Purchased capacity levelization 73.5 (33.1) (268.9) Transition cost recoveries 90.9 (85.2) (104.9) (Increase) Decrease in Receivables (645.6) (286.0) 106.5 Inventory 45.1 (26.2) (24.2) Other current assets 27.0 85.5 116.0 Increase (Decrease) in Accounts payable 576.7 53.5 (104.5) Taxes accrued (11.0) 25.7 (68.8) Interest accrued (18.5) 5.6 2.9 Other current liabilities (10.0) 17.7 (41.3) Other, net 93.2 (12.4) (87.3) ---------------- ---------------- ---------------- Net cash provided by operating activities 2,335.2 1,832.2 1,503.1 ---------------- ---------------- ---------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (1,393.9) (1,223.0) (1,436.5) Investment expenditures (156.1) (67.7) (15.2) Decommissioning, retirements and other investing (18.2) (26.9) (72.8) ---------------- ---------------- ---------------- Net cash used in investing activities (1,568.2) (1,317.6) (1,524.5) ---------------- ---------------- ---------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from the issuance of Long-term debt 362.8 421.5 974.9 Common stock 11.8 16.5 17.6 Payments for the redemption of Long-term debt (527.0) (480.9) (379.7) Common stock (159.0) - - Preferred stock - (100.5) (1.5) Net change in notes payable and commercial paper 159.3 193.2 67.9 Dividends paid (609.3) (590.5) (546.6) Other (12.1) (4.8) (23.2) ---------------- ---------------- ---------------- Net cash provided by (used in) financing activities (773.5) (545.5) 109.4 ---------------- ---------------- ---------------- Net increase (decrease) in cash and cash equivalents (6.5) (30.9) 88.0 Cash flows of Associated Natural Gas Corporation for the three months ended December 31, 1994 - - (116.6) Cash and cash equivalents at beginning of period 172.5 203.4 232.0 ---------------- ---------------- ---------------- Cash and cash equivalents at end of period $ 166.0 $ 172.5 $ 203.4 ================ ================ ================
See Notes to Consolidated Financial Statements 5 DUKE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (In millions)
December 31, December 31, 1996 1995 ---------------- ---------------- ASSETS Current Assets Cash and cash equivalents $ 166.0 $ 172.5 Receivables 1,888.0 1,194.8 Inventory 433.5 477.6 Current portion of natural gas transition costs 67.9 70.0 Current portion of purchased capacity costs 51.3 73.5 Other 157.1 171.4 ---------------- ---------------- Total current assets 2,763.8 2,159.8 ---------------- ---------------- Investments and Other Assets Investments in affiliates 502.9 327.6 Nuclear decommissioning trust funds 362.6 273.5 Pre-funded pension costs 360.6 339.3 Goodwill, net 222.1 247.5 Other 142.4 143.2 ---------------- ---------------- Total investments and other assets 1,590.6 1,331.1 ---------------- ---------------- Property, Plant and Equipment Cost 24,468.2 23,722.0 Less accumulated depreciation and amortization 9,199.1 8,857.0 ---------------- ---------------- Net property, plant and equipment 15,269.1 14,865.0 ---------------- ---------------- Regulatory Assets Purchased capacity costs 840.7 892.0 Debt expense 244.0 248.3 Regulatory asset related to income taxes 493.5 491.6 Natural gas transition costs 250.0 310.0 Environmental clean-up costs 153.2 197.9 Other 350.0 372.2 ---------------- ---------------- Total regulatory assets 2,331.4 2,512.0 ---------------- ---------------- Total Assets $ 21,954.9 $ 20,867.9 ================ ================
See Notes to Consolidated Financial Statements 6 DUKE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (In millions)
December 31, December 31, 1996 1995 ---------------- ---------------- LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts payable $ 1,286.5 $ 734.9 Notes payable and commercial paper 459.7 300.3 Taxes accrued 74.8 99.9 Interest accrued 124.3 142.8 Current portion of natural gas transition liabilities 84.4 125.0 Current portion of environmental clean-up liabilities 32.4 56.3 Current maturities of long-term debt 350.6 191.7 Other 508.3 441.7 ---------------- ---------------- Total current liabilities 2,921.0 2,092.6 ---------------- ---------------- Long-term Debt 5,485.1 5,803.0 ---------------- ---------------- Deferred Credits and Other Liabilities Deferred income taxes 3,568.5 3,484.3 Investment tax credit 250.1 261.3 Nuclear decommissioning costs externally funded 362.6 273.5 Natural gas transition liabilities 121.9 165.0 Environmental clean-up liabilities 188.9 225.8 Other 948.2 864.7 ---------------- ---------------- Total deferred credits and other liabilities 5,440.2 5,274.6 ---------------- ---------------- Minority Interests 83.4 1.2 ---------------- ---------------- Preferred and Preference Stock Preferred & preference stock with sinking fund requirements 234.0 234.0 Preferred & preference stock without sinking fund requirements 450.0 450.0 ---------------- ---------------- Total preferred and preference stock 684.0 684.0 ---------------- ---------------- Common Stockholders' Equity Common stock, no par, 500 million shares authorized; 359.4 million and 361.8 million shares outstanding at December 31, 1996 and 1995, respectively 4,289.3 4,296.8 Retained earnings 3,051.9 2,715.7 ---------------- ---------------- Total common stockholders' equity 7,341.2 7,012.5 ---------------- ---------------- Total Liabilities and Stockholders' Equity $ 21,954.9 $ 20,867.9 ================ ================
See Notes to Consolidated Financial Statements 7 DUKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (In millions)
YEAR ENDED DECEMBER 31 --------------------------------------------------------- 1996 1995 1994 ---------------- ---------------- ---------------- Common Stock Balance at beginning of year $ 4,296.8 $ 4,275.8 $ 4,242.7 Stock issued for purchase of assets - 2.5 10.0 Stock repurchased for merger (30.8) - - Dividend reinvestment and employee benefits 23.3 18.5 23.1 ---------------- ---------------- ---------------- Balance at end of year 4,289.3 4,296.8 4,275.8 ---------------- ---------------- ---------------- Retained Earnings Balance at beginning of year 2,715.7 2,292.2 1,974.4 Net income 1,074.3 1,018.1 864.1 Common stock dividends paid (565.6) (542.2) (496.4) Preferred and preference stock dividends paid (44.2) (48.9) (49.7) Capital stock transactions, net (128.3) (3.5) (0.7) Conform fiscal year end of Associated Natural Gas - - 0.5 ---------------- ---------------- ---------------- Balance at end of year 3,051.9 2,715.7 2,292.2 ---------------- ---------------- ---------------- Total Common Stockholders' Equity $ 7,341.2 $ 7,012.5 $ 6,568.0 ================ ================ ================
See Notes to Consolidated Financial Statements 8 DUKE ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 NOTE 1. OPERATIONS AND ACCOUNTING POLICIES Nature Of Operations Duke Energy Corporation (the Company) is one of North America's leading energy and energy services companies, involved in the production, transmission and sales of energy and delivery of energy related services worldwide. On June 18, 1997, Duke Power Company (Duke Power) changed its name to Duke Energy Corporation in accordance with the terms of a merger agreement with PanEnergy Corp (PanEnergy), pursuant to which the Company issued 158.3 million shares of its common stock in exchange for all of the outstanding common stock of PanEnergy. PanEnergy is involved in the transportation, storage, gathering and processing of natural gas, the production of natural gas liquids and is a marketer of natural gas, electricity, liquefied petroleum gases and related energy services. Pursuant to the merger, each share of PanEnergy common stock outstanding was converted into the right to receive 1.0444 shares of the Company's common stock. In addition, each outstanding option to purchase PanEnergy common stock became an option to purchase common stock of the Company, adjusted accordingly. The merger was accounted for as a pooling of interests and, accordingly, the consolidated financial statements for periods prior to the combination were restated to include the results of operations of PanEnergy. Operating revenues and net income previously reported by the separate companies and the combined amounts presented in the accompanying consolidated financial statements are as follows:
In Millions Duke Power PanEnergy Adjustments Combined - ---------------------------------------------- --------------- ----------------- ------------- Year Ended December 31, 1996 Operating revenues $4,758.0 $7,505.6 $38.8 $12,302.4 Net income $ 729.9 $ 344.4 - $ 1,074.3 Year Ended December 31, 1995 Operating revenues $4,676.6 $4,967.5 $50.6 $9,694.7 Net income $ 714.5 $ 303.6 - $1,018.1 Year Ended December 31, 1994 Operating revenues $4,489.0 $4,585.1 $40.9 $9,115.0 Net income $ 638.9 $ 225.2 - $ 864.1
The adjustment to operating revenues reflects a reclassification of PanEnergy's equity in earnings of unconsolidated affiliates from other income to revenues to be consistent with the Company's presentation. Consolidations The Company's consolidated financial statements reflect consolidation of all of its majority-owned subsidiaries. Investments in other entities that are not majority owned are accounted for using the equity method (see also Note 8). Intercompany transactions have been eliminated in consolidation. Use Of Estimates The consolidated financial statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported. However, actual results could differ from these estimates. 9 Reclassifications Certain amounts have been reclassified in the consolidated financial statements to conform to the current presentation. Cost-Based Regulation The Company's Electric Operations segment is subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission and The Public Service Commission of South Carolina. The interstate natural gas transmission and storage operations of the Company's Natural Gas Transmission segment are also subject to the rules and regulations of the FERC. These regulated operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the Company records certain assets and liabilities that result from the effects of the ratemaking process that would not be recorded under generally accepted accounting principles for non-regulated entities. The regulatory assets of the Company are classified as "Regulatory Assets" and regulatory liabilities are classified as "Deferred Credits and Other Liabilities" on the Consolidated Balance Sheets. The Company regularly evaluates the continued applicability of SFAS No. 71, considering such factors as regulatory changes and the impact of competition. Discontinuance of regulation or increased competition might require entities to reduce their asset balances to reflect a market basis less than cost and would also require entities to write off their associated regulatory assets. Management cannot predict the potential impact, if any, of discontinuance of regulation or increased competition on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. Revenues The Company recognizes revenues on sales of electricity as service is rendered, on sales of natural gas and petroleum products in the period of delivery, and transportation and storage revenues in the period service is provided. "Receivables" on the Consolidated Balance Sheets included $210 million and $206.8 million as of December 31, 1996 and 1995, respectively, for electric service that has been rendered but not yet billed to customers. When rate cases associated with the transportation of natural gas are pending final FERC approval, a portion of the revenues collected by interstate natural gas pipelines is subject to possible refund. The Company has established adequate reserves where required for such cases. (See also Note 4.) Commodity Price Risk Management Commodity derivatives utilized as hedges include futures, swaps and options. In order to qualify as a hedge, the price movements in the underlying commodity derivatives must be highly correlated with the hedged commodity. Gains and losses related to commodity derivatives which qualify as hedges of commodity commitments are recognized in income when the underlying hedged physical transaction closes and are included in "Natural gas and petroleum products purchased" or "Net interchange and purchased power" in the Consolidated Statement of Income. Gains and losses related to such instruments, to the extent settled in cash, are reported as "Other Current Liabilities" or "Other Current Assets" as appropriate, in the Consolidated Balance Sheet until recognized in income. Commodity derivatives utilized for trading include futures, swaps and options. Gains and losses on derivatives utilized for trading are recognized on a current basis and are also included in "Natural gas and petroleum products purchased" or "Net interchange and purchased power". (See also Note 7.) Nuclear Fuel Amortization of nuclear fuel is included in "Fuel used in electric generation" in the Consolidated Statements of Income. The amortization is recorded using the units-of-production method. Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. Payments made to the DOE for disposal costs are based on nuclear output and are included in "Fuel used in electric generation" in the Consolidated Statements of Income. A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid $9.5 million during 1996 and has 10 paid $45 million cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of $94.7 million in the Consolidated Balance Sheet at December 31, 1996. Deferred Returns And Allowance For Funds Used During Construction (AFUDC) Deferred returns represent the estimated financing costs associated with funding certain regulatory assets. These regulatory assets primarily arise from the Company's funding of purchased capacity costs above levels collected in rates. Deferred returns are non-cash items. They are primarily recognized as an addition to "Purchased capacity costs" and as an offsetting credit to "Other Income and Expenses." AFUDC represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. AFUDC, a non-cash item, is recognized as a cost of "Property, Plant and Equipment," with an offsetting credit to "Other Income and Expenses." After construction is completed, the Company is permitted to recover these costs, including a fair return, through their inclusion in rate base and in the provision for depreciation. Rates used for capitalization of deferred returns and AFUDC by the Company's regulated operations are calculated in compliance with FERC rules. Inventory Inventory consists primarily of materials and supplies, gas held for operations and coal held for electric generation. Inventory is recorded at the lower of cost or market primarily using the average cost method. Property, Plant And Equipment Property, plant and equipment is stated at original cost. The Company capitalizes all construction-related direct labor and materials, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of money. The cost of renewals and betterments of regulated units of property is also capitalized. The cost of repairs and replacements is charged to expense. At the time property, plant and equipment maintained by the Company's regulated operations are retired, the original cost plus the cost of retirement, less salvage, is charged to accumulated depreciation and amortization. When entire regulated operating units are sold or non-regulated properties are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced and any gain or loss is recorded to income, unless otherwise required by FERC. Depreciation of plant, property and equipment is generally computed using the straight-line method. Property, plant and equipment is evaluated for potential impairment based on the ability to identify separate cash flows generated therefrom. In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," the Company recognizes impairment losses on long-lived assets when book values exceed expected future cash flows. Goodwill Amortization The Company amortizes goodwill related to the purchases of Texas Eastern Corporation (TEC), certain other natural gas gathering, transmission and processing facilities, and certain engineering consulting businesses on a straight-line basis over 40 years, 15 years and 15 years, respectively. Accumulated amortization of goodwill at December 31, 1996 and 1995 was $99.7 million and $96.3 million, respectively. (See also Note 6.) Unamortized Debt Premium, Discount And Expense Expenses incurred in connection with the issuance of presently outstanding long-term debt issued for regulated operations, and premiums and discounts relating to such debt, are being amortized over the terms of the respective issues. Also, any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations used to finance regulated assets and operations are being amortized consistent with regulatory treatment of these items. 11 Income Taxes Duke Power and its subsidiaries and PanEnergy and its subsidiaries each file a consolidated federal income tax return. Federal income taxes have been provided by the Company on the basis of its separate company income and deductions in accordance with established practices of the consolidated group. Deferred income taxes have been provided for temporary differences. Temporary differences occur when events and transactions recognized for financial reporting result in taxable or tax-deductible amounts in different periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties. Common Stock Options The Company follows the intrinsic value method of accounting for common stock options and awards issued to employees. (See also Note 12.) Earnings Per Common Share The computation of earnings per common share is based on the monthly weighted-average number of shares of common stock outstanding. Convertible debt and unexercised stock options do not have a dilutive effect on the reported amount of earnings per common share. (See Notes 11, 12 and 13.) Consolidated Statements Of Cash Flows All liquid investments with maturities at date of purchase of three months or less are considered cash equivalents. Total income taxes paid were $549.9 million, $519.9 million and $418.4 million for the years ended December 31, 1996, 1995 and 1994, respectively. Interest paid, net of amounts capitalized, was $493.1 million, $481.6 million and $457.7 million for the years ended December 31, 1996, 1995 and 1994, respectively. NOTE 2. BUSINESS COMBINATIONS PanEnergy Trading And Market Services, L.L.C. On August 1, 1996, a wholly-owned subsidiary of the Company formed a natural gas and power marketing joint venture with Mobil Corporation (Mobil) affiliates. The marketing company (PTMS) conducts business as PanEnergy Trading and Market Services, L.L.C. in the United States and as PanEnergy Marketing L.P. in Canada. The Company operates the new entity and owns a 60% interest, with Mobil owning a 40% minority interest. Associated Natural Gas Corporation On December 15, 1994, a wholly-owned subsidiary of the Company merged with Associated Natural Gas Corporation (Associated), now PanEnergy Natural Gas Corporation, on a tax-free, stock-for-stock basis. The merger was accounted for under the pooling of interests method. The consolidated financial statements of the Company were restated in 1994 to include the results of Associated for the 12 months ended September 30. Effective with the date of the merger, the fiscal year end of Associated was changed from September 30 to December 31. Associated's net income for the three months ended December 31, 1994 was recorded directly to retained earnings and its cash activity for that period is shown separately on the consolidated statement of cash flows. 12 NOTE 3. BUSINESS SEGMENTS The Electric Operations segment is engaged in the generation, transmission, distribution and sale of electric energy in central and western North Carolina and the western portion of South Carolina, comprising the area known as the Piedmont Carolinas. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission and The Public Service Commission of South Carolina. The Natural Gas Transmission segment is involved in interstate transportation and storage of natural gas for customers in the Mid-Atlantic, New England, Midwest and Gulf Coast states. The interstate natural gas transmission and storage operations of the Company's wholly owned subsidiaries Texas Eastern Transmission Corporation (TETCO), Algonquin Gas Transmission Company (Algonquin), Panhandle Eastern Pipe Line Company (PEPL), and Trunkline Gas Company (Trunkline) are also subject to the rules and regulations of the FERC. The Energy Services segment is comprised of several separate business units. Field Services gathers and processes natural gas and produces natural gas liquids. The Trading and Marketing operations focus on marketing of natural gas, electricity and liquefied petroleum gases. Other business activities in this segment include ownership and operation of energy-related facilities, engineering consulting, construction and other related energy services. Parent and Other Operations include real estate operations, communications services, corporate costs and intersegment eliminations.
- ------------------------------ ------------ ------------ ---------- ---------- ---------- ------------ ------------- ------------ Earnings Before Depreciation Capital and Unaffiliated Intersegment Total Operating Interest & Investment Identifiable In Millions Revenues Revenues Revenues Income & Taxes Amortization Expenditures Assets - ------------------------------ ------------ ------------ ---------- ---------- ---------- ------------ ------------- ------------ - ---------------------------- Year Ended December 31, 1996 - ---------------------------- Electric Operations $4,498.4 $ - $4,498.4 $1,303.6 $1,419.5 $481.1 $609.8 $12,661.7 Natural Gas Transmission 1,468.8 86.4 1,555.2 584.5 596.2 228.2 185.3 5,267.2 Energy Services 6,186.6 12.4 6,199.0 197.0 202.7 67.1 590.5 2,772.2 Parent and Other Operations 148.6 (98.8) 49.8 73.5 75.8 13.0 164.4 1,253.8 --------- ---------- --------- -------- -------- ------- -------- --------- Total Consolidated $12,302.4 $ - $12,302.4 $2,158.6 $2,294.2 $789.4 $1,550.0 $21,954.9 ========= ========== ========= ======== ======== ====== ======== ========= - ------------------------------ Year Ended December 31, 1995 - ------------------------------ Electric Operations $4,512.4 $ - $4,512.4 $1,308.7 $1,381.2 $451.2 $704.0 $12,673.1 Natural Gas Transmission 1,480.2 53.1 1,533.3 564.1 569.7 228.5 227.0 5,352.6 Energy Services 3,528.7 1.0 3,529.7 118.5 130.1 44.4 247.8 1,600.6 Parent and Other Operations 173.4 (54.1) 119.3 77.0 109.5 13.0 111.9 1,241.6 --------- ---------- --------- -------- -------- ------- -------- --------- Total Consolidated $9,694.7 $ - $9,694.7 $2,068.3 $2,190.5 $737.1 $1,290.7 $20,867.9 ======== ========== ======== ======== ======== ====== ======== ========= - ------------------------------ Year Ended December 31, 1994 - ------------------------------ Electric Operations $4,362.9 $ - $4,362.9 $1,131.3 $1,228.5 $454.7 $796.6 $12,273.5 Natural Gas Transmission 1,642.0 44.8 1,686.8 533.9 521.6 216.8 303.4 5,655.8 Energy Services 2,946.0 60.2 3,006.2 79.1 89.6 34.5 274.1 1,247.9 Parent and Other Operations 164.1 (105.0) 59.1 61.7 67.3 10.8 77.6 1,077.0 --------- ---------- --------- -------- -------- ------- -------- --------- Total Consolidated $9,115.0 $ - $9,115.0 $1,806.0 $1,907.0 $716.8 $1,451.7 $20,254.2 ======== ========== ======== ======== ======== ====== ======== ========= - ------------------------------ ------------ ------------ ---------- ---------- ---------- ------------ ------------- ------------
NOTE 4. RATE MATTERS Electric Operations The North Carolina Utilities Commission (NCUC) and The Public Service Commission of South Carolina (PSCSC) must approve rates for retail sales within their respective states. The Federal Energy Regulatory Commission (FERC) must approve the Company's rates for electric sales to wholesale customers. Electric sales to the other joint owners of the Catawba Nuclear Station, which represent a substantial majority of the Company's electric wholesale revenues, are set through contractual agreements (see Note 5). Fuel costs are reviewed semiannually in the wholesale jurisdiction and annually in the South Carolina retail jurisdiction, with provisions for changing such costs in base rates. In the North Carolina retail jurisdiction, a review of fuel costs in rates is required annually and during general rate case proceedings. All jurisdictions allow the Company to adjust electric rates for past over- or under-recovery of fuel costs. Therefore, the Company reflects in revenues the difference between actual fuel costs incurred for electric operations and fuel costs recovered through rates. The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately 8 percent, affecting South Carolina retail customers. South Carolina retail sales represent approximately 30 percent of the Company's total electric retail sales. The rate reduction was reflected on bills rendered on or after June 1, 1996. This net decrement rider reflects an interim true-up decrement adjustment associated with the levelization of Catawba Nuclear Station purchased capacity costs and an interim true-up increment associated with amortization of the demand-side management deferral account. The rate adjustment was made because, in the South Carolina retail jurisdiction, cumulative levelized revenues associated with the recovery of Catawba purchased capacity costs had exceeded purchased capacity payments and accrual of deferred returns, and certain demand-side costs had exceeded the level reflected in rates (see also Note 5). Certain of the Company's electric wholesale customers, excluding the other Catawba joint owners, initiated proceedings in 1995 before the FERC concerning rate matters. The Company and nine of its eleven wholesale customers entered into a settlement in July 1996 which reduced the customers' electric rates by approximately 9 percent and renewed their contracts with the Company through the year 2000. Both of the customers that did not enter into the settlement have signed agreements to purchase electricity from other suppliers beginning in 1997. The eleven wholesale customers involved in this matter accounted for less than 2 percent of the Company's overall electric revenues during 1996. The two customers that have signed agreements with other suppliers accounted for less than 0.5 percent of the Company's 1996 overall electric revenues. Jurisdictional Transportation And Sales Rates For Natural Gas As noted previously, the interstate natural gas transmission operations of Texas Eastern Transmission Corporation (TETCO), Algonquin Gas Transmission Company (Algonquin), Panhandle Eastern Pipe Line Company (PEPL) and Trunkline Gas Company (Trunkline), and the liquefied natural gas (LNG) operations of Trunkline LNG Company and Algonquin LNG, Inc. are subject to the rules and regulation of the Federal Energy Regulatory Commission (FERC). PEPL. On April 1, 1992 and November 1, 1992, PEPL placed into effect, subject to refund, general rate increases. On September 12, 1996, PEPL filed a settlement proposal relating to both rate proceedings on behalf of itself and the majority of its largest customers. On December 20, 1996, FERC approved PEPL's settlement agreement which resolves refund matters and establishes prospective rates for settling parties. The agreement, which remains subject to rehearing, terminates other actions relating to these proceedings as well as PEPL's restructuring of rates and transition cost recoveries related to Order 636. As a result of the resolution of certain proceedings, PEPL recorded earnings before interest and taxes of $8 million, $20.6 million and $25 million in 1996, 1995 and 1994, respectively. Trunkline. Effective August 1, 1996, Trunkline placed into effect a general rate increase, subject to refund. Algonquin. On June 14, 1996, Algonquin submitted a compliance filing reflecting changes in net plant, property and equipment pursuant to a previous rate settlement. On October 16, 1996, FERC accepted the filing and denied all protests. 14 FERC Order 636 And Transition Costs The Company's interstate natural gas pipelines primarily provide transportation and storage services pursuant to FERC Order 636. Order 636 allows pipelines to recover eligible costs resulting from implementation of the order (transition costs). On July 16, 1996, the U.S. Court of Appeals for the District of Columbia upheld, in general, all aspects of Order 636 and remanded certain issues for further explanation. One of the issues remanded for further explanation is whether pipelines should be entitled to recover 100% of gas supply realignment (GSR) costs. This matter is substantially mitigated by TETCO's and PEPL's transition cost settlements. In 1994, TETCO refunded $84 million to customers pursuant to a FERC-approved settlement that resolved regulatory issues related primarily to Order 636 transition costs and a number of other issues related to services prior to Order 636. TETCO's final and nonappealable settlement provides for the recovery of certain transition costs through volumetric and reservation charges through 2002 and beyond, if necessary. Pursuant to the settlement, TETCO will absorb a certain portion of the transition costs, the amount of which continues to be subject to change dependent upon natural gas prices and deliverability levels. In 1995, based upon producers' discoveries of additional natural gas reserves, TETCO increased the estimated liabilities for transition costs by $125.8 million. Under the terms of the existing settlement, regulatory assets were increased $85.8 million and TETCO recognized a $40 million charge to operating expenses ($26 million after tax). The Company believes the exposure associated with gas purchase contract commitments is substantially mitigated by transition cost recoveries pursuant to customer settlements, Order 636 and other mechanisms, and that this issue will not have a material adverse effect on consolidated results of operations or financial position. NOTE 5. JOINT OWNERSHIP OF GENERATING FACILITIES The Company previously sold interests in both units of the Catawba Nuclear Station. The other owners of portions of the Catawba Nuclear Station and supplemental information regarding their ownership are as follows: Owner Ownership Interest in the Station ------------------------------------------- ------ ------------------- North Carolina Municipal Power Agency 37.5% Number 1 (NCMPA) North Carolina Electric Membership 28.125% Corporation (NCEMC) Piedmont Municipal Power Agency 12.5% (PMPA) Saluda River Electric Cooperative, Inc. 9.375% (Saluda River) Each owner has provided its own financing for its ownership interest in the station. The Company retains a 12.5 percent ownership interest in the Catawba Nuclear Station. As of December 31, 1996, $497.3 million of "Property, plant and equipment" represents the Company's investment in Units 1 and 2. Accumulated depreciation and amortization of $192.1 million associated with Catawba has been recorded as of year-end 1996. The Company's share of operating costs of Catawba is included in the Consolidated Statements of Income. In connection with the joint ownership, the Company has entered into contractual agreements with the other joint owners to purchase declining percentages of the generating capacity and energy from the plant. These purchased power agreements were effective beginning with the commercial operation of each unit. Unit 1 and Unit 2 began commercial operation in June 1985 and August 1986, respectively. The purchased power agreements were established for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda River. While the purchased power agreements with NCMPA and PMPA extend for 15 years, a 15 significant decrease in the percentage of capacity and energy the Company is obligated to purchase occurs in the 11th calendar year of operation for each unit. This significant decrease occurred in 1995 for Unit 1 and 1996 for Unit 2. The agreements also provide for supplemental power sales by the Company to the other joint owners. Such power sales are to satisfy capacity and energy needs of the other joint owners beyond the capacity and energy which they retain from Catawba or potentially acquire in the form of other resources. The agreements further provide the other joint owners the ability to secure such supplemental requirements outside of these contractual agreements following an appropriate notice period. NCEMC and Saluda River have given appropriate notice that they intend to acquire their supplemental capacity requirements outside of these agreements effective January 1, 2001 and January 1, 2002, respectively, thus relieving the Company of the obligation to serve this portion of load. As the joint owners retain more capacity and energy from Catawba, or a third party, supplemental power sales are expected to decline. The agreements with each of the other joint owners include provisions that the Company will provide generating reserves to backstand the other joint owners' retained capacity in the Catawba plant at the system average cost of installed capacity. Additionally, the agreements include certain reliability exchanges designed to manage outage-related risks by exchanging energy entitlements between the Catawba Nuclear Station and the McGuire Nuclear Station, impacting the Company as well as all the other joint owners. Purchased energy cost payments are based on variable operating costs and are a function of the generation output of Catawba. Purchased capacity payments are based on the fixed costs of the plant and include the capital costs and fixed operating and maintenance costs. Actual purchased capacity costs for 1996 and projected obligations for 1997 through 2001, including the impact of the 1995 settlement agreement with NCMPA and PMPA (see Note 15), are as follows (dollars in millions): Purchased Purchased Total Year Capacity Capacity Purchased Capital Cost Fixed O&M Capacity --------------- --------------- -------------- -------------- 1996 Actual $84.3 $40.5 $124.8 1997 Projected $67.0 $34.9 $101.9 1998 Projected $48.4 $26.4 $ 74.8 1999 Projected $35.3 $19.1 $ 54.4 2000 Projected $ 4.3 $ 2.5 $ 6.8 2001 Projected --- --- --- Effective in its November 1991 rate order, the North Carolina Utilities Commission reaffirmed the Company's recovery, on a levelized basis, of the capital costs and fixed operating and maintenance costs of capacity purchased from the other joint owners. The Public Service Commission of South Carolina in its November 1991 rate order reaffirmed the Company's recovery on a levelized basis of the capital costs of capacity purchased from the other joint owners. Levelization was reaffirmed through inclusion in rates approved in March 1992 by the Federal Energy Regulatory Commission (FERC). The portion of purchased capacity subject to levelization not currently recovered in rates is being deferred, and the Company is recording a deferred return on the accumulated balance. The Company recovers the accumulated balance, including the deferred return, when the sum of the declining purchased capacity payments and accrual of deferred returns for the current period drops below the levelized revenues. Jurisdictional levelizations are intended to recover total costs, including deferred returns, and are subject to adjustments, including final true-ups. The Company recovers the costs of purchased energy and the non-levelized portion of purchased capacity on a current basis. The current levelized revenues approved in the Company's last general rate proceedings are $211.4 million, $94.1 million and $6.8 million for North Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively. Purchased power costs, subject to levelization, are deferred based on allocation factors of approximately 62 percent, 26 percent and 2 percent for North Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively. The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider for an interim true-up adjustment (see Note 4). The Company also recovers an allocated amount of purchased power costs in the pricing of supplemental sales made to the other joint owners on a current basis. During 1996, in the North Carolina retail and FERC wholesale jurisdictions, annual levelized revenues exceeded purchased capacity payments and the accrual of deferred returns for the first time. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments and accrual of deferred returns. For the years ended December 31, 1996, 1995 and 1994, the Company recorded purchased capacity and energy costs from the other joint owners of $151.2 million, $388.2 million and $604.5 million, respectively. These amounts, after adjustments for the costs of capacity purchased not reflected in current rates, are included in "Net interchange and purchased power" in the 16 Consolidated Statements of Income. As of December 31, 1996 and 1995, $892 million and $965.5 million, respectively, associated with the cost of capacity purchased but not reflected in current rates have been accumulated in the Consolidated Balance Sheets as "Purchased capacity costs" and "Current portion of purchased capacity costs". NOTE 6. INCOME TAX EXPENSE Income tax expense for the years ended December 31, 1996, 1995 and 1994 consisted of the following (dollars in millions): 1996 1995 1994 --------- --------- ---------- Current Income Taxes Federal $514.3 $452.0 $290.6 State 108.8 97.0 58.8 ----- ----- ----- Total current income taxes 623.1 549.0 349.4 ----- ----- ----- Deferred taxes, net Federal 73.1 105.2 178.0 State 12.8 21.2 42.3 ----- ----- ----- Total deferred taxes, net 85.9 126.4 220.3 ---- ----- ----- Investment tax credit amortization (11.2) (11.2) (11.3) ------ ------ ------ Total income tax expense $697.8 $664.2 $558.4 ====== ====== ====== Total income tax differs from the amount computed by applying the federal income tax rate to income before income tax. The reasons for this difference are as follows (dollars in millions):
1996 1995 1994 ------------ ------------ --------------- Federal income tax rate 35% 35% 35% === === === Income tax, computed at the statutory rate $626.1 $588.8 $497.9 Adjustments resulting from: State income tax, net of federal income tax effect 78.6 76.5 64.9 Other items, net (6.9) (1.1) (4.4) ----- ----- ----- Total income tax $697.8 $664.2 $558.4 ====== ====== ====== Effective tax rate 39.0% 39.5% 39.3% ===== ===== =====
The tax effects of temporary differences that resulted in deferred income tax assets and liabilities, and a description of the significant items that created these differences, are as follows (dollars in millions):
December 31, December 31, 1996 1995 ---------------- ---------------- Property, plant and equipment * $2,290.6 $2,247.8 Regulatory assets * 687.4 757.6 Regulatory asset related to restating to pre-tax basis 601.9 606.1 Deferred credits and other liabilities (334.3) (375.1) Other 322.9 247.9 -------- -------- Total deferred income taxes $3,568.5 $3,484.3 ======== ========
* The net regulatory asset related to income taxes is $493.4 million for 1996 and $491.6 million for 1995. 17 Total deferred income tax liabilities were $4,409 million and $4,452.7 million at December 31, 1996 and 1995, respectively. Total deferred income tax assets were $981.6 million and $1,110.9 million at December 31, 1996 and 1995, respectively. The valuation reserve for deferred tax assets was $141.1 million and $142.5 million at December 31, 1996 and 1995, respectively. In 1990, the Internal Revenue Service (IRS) issued regulations which disallow for tax purposes losses incurred in the Company's 1989 sales of certain assets that were acquired in the purchase of Texas Eastern Corporation. Consequently, the Company established a provision in 1990 for this and certain other issues, resulting in an increase in goodwill and deferred income tax liability. Following further discussions with the IRS, the Company revised its estimates in 1994 with respect to the disallowed loss issue, and in 1995 and 1996 with respect to the remaining issues. As a result, the Company reduced the related goodwill and deferred income tax liability by approximately $40 million, $100 million and $200 million in 1996, 1995 and 1994, respectively. NOTE 7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Financial Instruments In order to obtain variable rate financing at an attractive cost, the Company entered into various interest rate swap agreements. At December 31, 1996 and 1995, the following swaps were outstanding (dollars in millions):
Weighted Weighted Weighted Average Average Average Face Rate Rate Rate Series Issued Year Due Value 1996 1995 1994 ---------------- ---------- ----------- ---------- ----------- ------------ ------------ 8% Series B 1994 1999 $200 5.64% 6.14% 5.95% 7 1/2% Series B 1995 2025 $100 6.69% 7.06% ---
The interest rate swaps are reset quarterly based upon the three-month London Interbank Offered Rate (LIBOR). As a result of the interest rate swap contracts, interest expense on the Consolidated Statements of Income is recognized at the weighted average rate for the year tied to the LIBOR rate. The Company has implemented an agreement to sell with limited recourse, on a continuing basis, current accounts receivable at a discount. The Company received $100 million for accounts receivable sold that remained outstanding at December 31, 1996. In 1996, TETCO received $98.6 million from the sale of the right to collect certain Order 636 transition costs, with limited recourse. In 1993, the Company sold LNG project settlement receivables, with limited recourse. At December 31, 1996, $87.3 million and $29.9 million remained outstanding on the transition cost recovery rights sold and the LNG settlement receivables sold, respectively. In the opinion of management, the probability that the Company will be required to perform under any of the above recourse provisions is remote. Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset currency fluctuations between the U.S. dollar and the Chilean peso associated with expected equity contributions to an affiliate in 1995, 1996 and 1997. The hedge transaction has a notional amount of approximately $4.4 million at December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses associated with the hedge as an adjustment to investments in affiliates. Fair Market Value Of Financial Instruments The fair value of the Company's financial instruments is summarized below. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 1996 and 1995 are not necessarily indicative of the amounts the Company could have realized in current market exchanges. 18
- ---------------------------------------- -------------------------- ----------------------------- In Millions December 31, 1996 December 31, 1995 Assets (Liabilities) Assets (Liabilities) - ---------------------------------------- -------------------------- ----------------------------- Book Value Approximate Book Value Approximate Fair Value Fair Value ----------- -------------- ----------- ----------------- Cash and cash equivalents $166.0 $166.0 $172.5 $172.5 Notes payable and commercial paper (459.7) (459.7) (300.3) (300.3) Long-term debt (1) (5,881.5) (5,999.0) (6,048.9) (6,430.5) Foreign currency exchange contract (3) -- -- 32.7 34.0 Interest rate swaps (3) -- 12.0 -- 23.1 Nuclear decommissioning trust funds (2) 362.6 362.6 273.5 273.5 Preferred stock (1) (684.0) (699.0) (684.0) (689.0) - ---------------------------------------- ----------- -------------- ----------- -----------------
(1) The majority of estimated fair value amounts of long-term debt and preferred stock were obtained from independent parties. (2) External funds have been established, as required by the Nuclear Regulatory Commission, as a mechanism to fund certain costs of nuclear decommissioning. Currently, these nuclear decommissioning trust funds are invested in U.S. stocks, bonds and cash equivalents. (3) Amounts shown for foreign currency exchange contracts and interest rate swaps represent estimated amounts the Company would receive if agreements were settled, considering current market rates and the creditworthiness of the parties to the agreements. The following financial instruments have no book value associated with them and there are no fair values readily determinable since quoted market prices are not available: recourse provisions of the TEPPCO Partners, L.P. First Mortgage Notes (see Note 15); and the LNG project settlement, trade accounts receivable and Order 636 transition cost recovery sales agreements. Commodity Risk Management At December 31, 1996, the Company held or issued several instruments that reduce the Company's exposure to market fluctuations in the price and transportation costs of natural gas, petroleum products and power. The Company's market exposure, primarily within PTMS, arises from inventory balances and fixed-price purchase and sale commitments that extend for periods of up to 10 years. The Company uses futures, swaps and options to manage and hedge price and location risk related to these market exposures. PTMS also provides risk management services to its customers through a variety of energy commodity financial instruments. In addition to hedging activities, the Company also engages in the trading of such instruments, and therefore experiences net open positions in terms of price, volume and specified delivery point. The Company manages open positions with strict policies which limit its 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 as well as a total value at risk measurement. The weighted-average life of the Company's commodity risk portfolio was approximately 11 months at December 31, 1996. Natural gas futures involve the buying or selling of natural gas at a fixed price. Over-the-counter swap agreements require the Company to receive or make payments based on the difference between a specified price and the actual price of natural gas. The Company uses futures and swaps to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas. Natural gas options held to hedge price risk provide the right, but not the requirement, to buy or sell natural gas at a fixed price. The Company utilizes options to manage margins and to limit overall price risk exposure. At December 31, 1996 and 1995, the Company had outstanding futures, swaps and options for an absolute notional contract quantity of 104 billion cubic feet (Bcf) and 223 Bcf of natural gas, respectively, which are in place to offset the risk of price fluctuations under fixed-price commitments for delivering and purchasing natural gas. The gains, losses and costs related to those financial instruments that qualify as a hedge are not recognized until the underlying physical transaction occurs. At December 31, 1996 and 1995, the Company had unrecognized net losses of $5.1 million and $15.4 million, respectively, related to financial instruments which are offset by corresponding unrecognized net gains from the Company's obligations to sell physical quantities of gas and power. The fair value of energy commodity swaps held at December 31, 1996 was an asset of $86.5 million with a notional amount of $95.9 million. During 1996, 1995 and 1994, the Company recognized gains of $25.4 million, $10.5 million and $0.7 million, respectively, from trading activities. The values of energy commodities futures, swaps and options held for trading purposes were as follows: 19
--------------------------- ------------------------- ---------------------------- In Millions 1996 1995 --------------------------- ------------------------- ---------------------------- Assets Liabilities Assets Liabilities ----------- ------------- ----------- ---------------- Fair Value at December 31 $719 $731 $406 $424 Average Fair Value 458 466 277 289 Notional Amount 698 692 430 447 --------------------------- ----------- ------------- ----------- ----------------
Market And Credit Risk New York Mercantile Exchange (Exchange) traded futures and option contracts are guaranteed by the Exchange and have nominal credit risk. On all other transactions described above, the Company is exposed to credit risk in the event of nonperformance by the counterparties. For each counterparty, the Company analyzes their financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The change in market value of Exchange-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Swap contracts and most other over-the-counter instruments are generally settled at the expiration of the contract term and may be subject to margin requirements with the counterparty. NOTE 8. INVESTMENT IN AFFILIATES Certain investments, where the Company's ownership in domestic and international affiliates is 50 percent or less, are accounted for by the equity method. These investments include ownership interests in various power and natural gas development projects; start-up personal communications services; marketing of natural gas, electric power, and development of other energy services; participation in various construction and support activities for fossil-fueled generating plants; and real-estate development projects. The Company's proportionate share of net income from these affiliates for the years ended December 31, 1996, 1995 and 1994 was $32.7 million, $59.8 million and $47.9 million, respectively. These amounts are reflected in "Other operating revenues" on the Consolidated Statements of Income. A summary of assets and liabilities of these affiliates follows (dollars in millions): ------------------------------------- -------------- --------------- In Millions December 31, December 31, 1996 1995 ------------------------------------- -------------- --------------- Assets of affiliates $7,209.0 $6,232.1 Liabilities of affiliates $4,715.0 $4,250.4 ------------------------------------- -------------- --------------- In addition, the Company had outstanding loans to certain affiliates of $2.9 million and $23.2 million at December 31, 1996 and 1995, respectively. 20 NOTE 9. PROPERTY, PLANT AND EQUIPMENT A summary of property, plant and equipment by classification follows (dollars in millions):
Depreciation December 31, December 31, Rates 1996 1995 --------------- ----------------- --------------- Electric Plant In Service Production 2%-5% $ 7,278.4 $ 7,154.3 Transmission 2%-3% 1,543.7 1,532.3 Distribution 2%-4% 4,303.9 4,105.5 General plant 0%-8% 1,068.3 1,030.2 Nuclear fuel --- 604.8 731.7 Construction work in progress --- 389.0 382.6 ---------- --------- Total electric plant in service 15,188.1 14,936.6 ---------- --------- Natural Gas Plant In Service Transmission 2%-7% 6,206.7 6,044.8 Gathering 1%-7% 431.0 511.9 Processing 4%-5% 508.4 144.1 Underground storage 2%-4% 450.6 488.3 LNG facilities and vessels 0%-3%* 751.0 751.2 General plant 3%-33% 348.1 318.5 Construction work in progress --- 126.7 141.9 ---------- --------- Total natural gas plant in service 8,822.5 8,400.7 ---------- --------- Other Property and Equipment 3%-33% 457.6 384.7 ---------- --------- Total Property, Plant and Equipment 24,468.2 23,722.0 Less accumulated depreciation (including amortization of nuclear fuel: 1996 - $363.3 million; 1995 - $453.9 million) 9,199.1 8,857.0 ---------- --------- Net property, plant and equipment $ 15,269.1 $14,865.0 ========== =========
* A portion of these assets are depreciated using the modified units of production method. A summary of accumulated depreciation for property, plant and equipment by classification follows (dollars in millions): December 31, December 31, 1996 1995 ----------------- --------------- Electric Plant In Service $ 5,801.8 $ 5,576.1 Natural Gas Plant In Service 3,365.8 3,250.9 Other Property and Equipment 31.5 30.0 --------- --------- Total Accumulated Depreciation $ 9,199.1 $ 8,857.0 ========= ========= 21 NOTE 10. SHORT-TERM DEBT AND CREDIT FACILITIES The following credit facilities were available to the Company at December 31, 1996 and 1995 (dollars in millions):
--------------------------------- --------------- ---------------- -------------- ----------------- Credit Credit Facilities at Outstanding at Facilities at Outstanding at December 31, December 31, December December 31, In Millions 1996 1996 31, 1995 1995 --------------------------------- --------------- ---------------- -------------- ----------------- Annually renewable facilities $ 64.9 $ 8.6 $ 64.9 $ 29.3 364-day facilities (d) 400.0 - - - Two-year revolving facilities (a) 40.0 - 40.0 - Four-year revolving facilities (b) 235.0 42.0 210.0 30.0 Five-year facilities (c) 755.0 - 1,155.0 - -------- ----- ---------- ----- Total Consolidated $1,494.9 $50.6 $ 1,469.9 $59.3 ======== ===== ========== ===== --------------------------------- --------------- ---------------- -------------- -----------------
(a) At December 31, 1996 and 1995, the Company had $40 million of pollution control bonds, included in long-term debt, backed by the two-year revolving facilities. (b) The outstanding balance of $42 million and $30 million at December 31, 1996 and 1995, respectively, were included in long-term debt. (c) The Company had $130 million in commercial paper, included in long-term debt, outstanding throughout 1996 and 1995 backed by these facilities. (d) The Company had $194.2 million and $126 million in commercial paper, included in short-term debt, outstanding at December 31, 1996 and 1995, respectively, backed by these facilities. In addition to amounts borrowed under the credit facilities and commercial paper program, the Company had $251.9 million and $145 million of short-term borrowings from banks outstanding at December 31, 1996 and 1995, respectively. A summary of short-term borrowings is as follows (dollars in millions):
1996 1995 1994 ------------- ------------ ------------- Amount outstanding at end of period - average rate of 6.16% as of December 31, 1996, 6.09% as of December 31, 1995, and 6.02% as of December $459.7 $300.3 $107.1 31, 1994 Maximum amount outstanding during the period $501.4 $409.3 $147.1 Average amount outstanding during the period $182.4 $152.8 $25.1 Weighted-average interest rate for the period - computed on a daily 5.92% 6.15% 4.42% basis
22 NOTE 11. LONG-TERM DEBT Long-term debt outstanding as of December 31, 1996 and 1995 consisted of the following (dollars in millions):
Year Due December 31, December 31, 1996 1995 ------------ ---------------- -------------- Duke Power (a) First and refunding mortgage bonds: 6.59% 1996 $ -- $3.0 5 3/8% 1997 72.6 72.6 5 5/8% 1997 100.0 100.0 5.17% 1998 50.0 50.0 7.5% 1999 100.0 100.0 6 1/4% 1999 65.0 65.0 5.76% 1999 5.0 5.0 5.78% 1999 25.0 25.0 5.79% 1999 30.0 30.0 8% B 1999 200.0 200.0 7% 2000 100.0 100.0 7% B 2000 100.0 100.0 5 7/8% 2001 150.0 150.0 6 5/8% B 2003 100.0 100.0 5 7/8% C 2003 75.0 75.0 6.125% 2003 75.0 75.0 8% 2004 75.0 75.0 6 1/4% B 2004 100.0 100.0 7.37%-7.41% 2004 100.0 100.0 7% 2005 200.0 200.0 6 3/8% 2008 125.0 125.0 8 3/4% 2021 150.0 150.0 8 3/8% B 2021 150.0 150.0 8 5/8% 2022 100.0 100.0 7 3/8% 2023 200.0 200.0 6 7/8% B 2023 200.0 200.0 7 7/8% 2024 150.0 150.0 6 3/4% 2025 150.0 150.0 7 1/2% B 2025 100.0 100.0 8.27% 2025 21.0 21.0 8.27% 2025 50.0 50.0 8.28% 2025 2.0 2.0 8.30% 2025 5.0 5.0 8.95% 2027 15.6 15.7 7% 2033 150.0 150.0 Pollution control bonds: 7.70% 2012 20.0 20.0 7.75% B 2017 10.0 10.0 7.50% 2017 25.0 25.0 3.58% 2014 40.0 40.0 5.80% 2014 77.0 77.0 Capitalized leases 11.3 7.5 Other long-term debt 146.5 147.4 PanEnergy Bonds: 7 3/4% 2022 328.0 328.0 Swiss Franc 1996 -- 86.7 8 5/8% Debentures 2025 100.0 100.0 Notes: Medium term, Series A, 8.5-9% 1996-1997 114.5 139.0 9.55% 1996-1999 41.3 55.0 23 8 5/8% 1999 100.0 100.0 9.9% 2000-2003 45.0 45.0 7 3/8% 2003 100.0 -- 9% convertible 1997-2004 10.0 10.0 7 1/4% 2005 100.0 100.0 7% 2006 150.0 -- TETCO Debentures: 10 1/8% 2011 -- 100.0 10% 2011 -- 150.0 Notes: 10 3/8% 2000 200.0 200.0 10% 2001 100.0 100.0 8% 2002 100.0 100.0 8 1/4% 2004 100.0 100.0 Medium term, Series A, 7.64-9.07% 1999-2012 100.0 100.0 Algonquin Notes: 8.795-8.936% 1996 -- 50.0 9.13% 2001-2003 100.0 100.0 PEPL Notes: 7 7/8% 2004 100.0 100.0 Debentures: 7.95% 2023 100.0 100.0 7.2% 2024 100.0 100.0 PanEnergy Natural Gas 6.3% Notes 1999-2003 -- 40.0 Panhandle Gathering Company 4% Notes 1996 -- 4.5 Other -- .1 Crescent Resources, Inc. (b) 118.0 130.7 ---------------------------- Nantahala Power and Light Company 68.4 33.3 --------------------------------- Unamortized debt discount and premium, net (60.5) (98.8) ------ ------ Total long-term debt 5,835.7 5,994.7 Current maturities of long-term debt (350.6) (191.7) ------- ------- Total long-term portion $5,485.1 $5,803.0 ======== ========
(a) Substantially all of Duke Power's electric plant was mortgaged as of December 31, 1996. (b) Substantial amounts of Crescent Resources, Inc.'s real estate development projects, land and buildings are pledged as collateral. As of December 31, 1996 and 1995, the Company had $40 million in pollution control revenue bonds backed by an unused, two-year revolving credit facility of $40 million. In addition, the Company had $130 million in commercial paper outstanding throughout 1996 and 1995 backed by unused five-year revolving credit facilities. These facilities are on a fee basis. Both the $40 million in pollution control bonds and the $130 million in commercial paper are included in long-term debt. As of December 31, 1996, Crescent Resources, Inc. had $45.4 million in mortgage loans which mature through 1999 and $30.6 million in mortgage loans maturing in 2000 or thereafter. Additionally, Crescent Resources, Inc. had $42 million outstanding at December 31, 1996, included in long-term debt on a $75 million four-year revolving credit facility. Interest rates are variable 24 and at December 31, 1996, ranged from 5.95 percent to 7.10 percent. As of December 31, 1996, Nantahala Power and Light Company had $68 million in senior notes maturing in 2011, 2012 and 2016. The notes carry fixed interest rates of 9.21 percent, 7.45 percent and 6.90 percent and require monthly payments of principal beginning in 1997, 1998 and 2002, respectively. PanEnergy's 9% convertible notes entitle the holders, at their option, to convert the notes into 451,875 shares of PanEnergy common stock. This conversion right contains various anti-dilutive provisions, including a provision to adjust the conversion rate if PanEnergy sells shares at a price less than the current market price. The annual maturities of consolidated long-term debt, including capitalized lease principal payments through 2001 were as follows (dollars in millions): 1997 $350.6 1998 76.6 1999 607.5 2000 459.6 2001 315.0 On October 1, 1996, TETCO redeemed its $150 million, 10% debentures due 2001 and its $100 million, 10 1/8% debentures also due 2011. TETCO recorded a non-cash extraordinary charge of $16.7 million (net of income tax of $10.3 million) related to the unamortized discount on this early retirement of debt. Earnings per common share for 1996 were reduced $0.05 as a result of this charge. The Company has authority to issue up to $1 billion aggregate principal amount of debt securities under a shelf registration statement filed with the Securities and Exchange Commission (SEC). Such debt securities may be issued as First and Refunding Mortgage Bonds, Senior Notes or Subordinated Debentures. PanEnergy, TETCO and PEPL have effective shelf registration statements with the SEC for the issuance of $50 million, $100 million and $100 million, respectively, of unsecured debt securities. NOTE 12. STOCK BASED COMPENSATION Stock Options and Awards Effective with the merger, each share of PanEnergy common stock outstanding immediately prior to the merger was converted into the right to receive 1.0444 shares of the Company's common stock. Each option to purchase PanEnergy common stock that was outstanding prior to the merger was assumed by the Company and will be exercisable upon the same terms as under the applicable PanEnergy stock option plan and option agreement, except that such option will become an option to purchase the Company's common stock, appropriately adjusted. Each award of restricted PanEnergy common stock outstanding and not vested prior to the merger was assumed by the Company and such shares of restricted PanEnergy common stock will be exchanged for shares of the Company's restricted common stock. Under the PanEnergy 1994 Long Term Incentive Plan stock options and awards for up to three million shares of common stock may be granted to employees. Under the 1989 Nonemployee Directors Stock Option Plan the company may grant options for up to 200,000 shares to members of the Board of Directors. Under each plan, the exercise price of each option granted equals the market price of the Company's common stock on the date of grant. Vesting periods range from one to five years with a maximum term of 10 years. In 1996, the Company granted 150,471 performance-based stock awards and 78,330 fixed stock awards with an average grant date fair value of $28 per share. The Company recognized compensation expense of $8.3 million in 1996 and none in 1995 for stock options and stock awards. 25 A summary of the Company's stock option grants follows: Options Average (000's) Exercise Price ----------------------------------------- Outstanding at Dec. 31, 1993 1,839 $18 Granted 351 23 Exercised (63) 15 Expired (34) 23 Converted * 1,644 12 ----- Outstanding at Dec. 31, 1994 3,737 16 Granted 959 20 Exercised (1,075) 13 Expired (62) 22 ---- Outstanding at Dec. 31, 1995 3,559 18 Granted 498 28 Exercised (712) 16 Expired (71) 22 ---- Outstanding at Dec. 31, 1996 3,274 20 ===== *Represents conversion of stock options outstanding of Associated Natural Gas Corporation into equivalent PanEnergy and subsequently Duke Energy options. The Company had 2,990 options and 2,394 options exercisable at December 31, 1994 and 1995, with average exercise prices of $15 and $16 per option, respectively. Details of stock options outstanding and options exercisable at December 31, 1996 follows: Outstanding Exercisable Range of Average Average Average Exercise Number Remaining Exercise Number Exercise Prices (000's) Life (Years) Price (000's) Price ------------------------------------------------------------------------ $10 to $13 266 4.5 $11 266 $11 $15 to $20 784 5.6 17 784 17 $21 to $25 1,705 7.3 22 1,117 22 $26 to $28 392 8.9 28 9 26 $31 to $32 127 7.8 32 20 31 ----------- ----------- Total 3,274 2,196 19 =========== =========== Fair Value Information The weighted-average fair value of options granted during 1994 and 1995 was $7 per option each year, and $9 per option during 1996. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for 1995 and 1996 grants: stock dividend yield of 2.6%; expected stock price volatility of 26%; 1994 Plan risk-free interest rates of 7.7% and 5.7 % for 1995 and 1996, respectively; 1989 Plan risk-free interest rates of 6.9% and 6.8% for 1995 and 1996, respectively; and expected option lives of seven years. Had compensation expense for stock-based compensation been determined based on the fair value at the grant dates, the Company's 1996 net income would have been $1,073.7 million, or $2.85 per share, and 1995 net income would have been $1,016.9 million, or $2.68 per share. 26 NOTE 13. PREFERRED AND PREFERENCE STOCK The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1996 and 1995: Par Shares Value (in millions) -------- ------------- Preferred Stock $100 12.5 Preferred Stock A $ 25 10.0 Preference Stock $100 1.5 As of December 31, 1996 and 1995, there were no shares of preference stock outstanding. Preferred stock without sinking fund requirements as of December 31, 1996 and 1995, was as follows (dollars in millions):
Year Shares Rate/Series Issued Outstanding 1996 1995 --------------------------- ---------- -------------- ----------- ----------- 4.50% C 1964 350,000 $35.0 $35.0 5.72% D 1966 350,000 35.0 35.0 6.72% E 1968 350,000 35.0 35.0 7.85% S 1992 600,000 60.0 60.0 7.00% W 1993 500,000 50.0 50.0 7.04% Y 1993 600,000 60.0 60.0 7.72% (Preferred Stock A) 1992 1,600,000 40.0 40.0 6.375% (Preferred Stock A) 1993 2,400,000 60.0 60.0 Auction Series A 1990 750,000 75.0 75.0 ------ ------ Total $450.0 $450.0 ====== ======
Preferred stock with sinking fund requirements as of December 31, 1996 and 1995, was as follows (dollars in millions):
Year Shares Rate/Series Issued Outstanding 1996 1995 --------------------------- ---------- -------------- ----------- ----------- 5.95% B (Preferred Stock A) 1992 800,000 $20.0 $20.0 6.10% C (Preferred Stock A) 1992 800,000 20.0 20.0 6.20% D (Preferred Stock A) 1992 800,000 20.0 20.0 7.50% R 1992 850,000 85.0 85.0 6.20% T 1992 130,000 13.0 13.0 6.30% U 1992 130,000 13.0 13.0 6.40% V 1992 130,000 13.0 13.0 6.75% X 1993 500,000 50.0 50.0 ------ ------ Total $234.0 $234.0 ====== ======
The annual sinking fund requirements through 2001 are $0 in 1997, $4.3 million in 1998, $24.3 million in 1999, $37.3 million in 2000 and $37.3 million in 2001. Some additional redemptions are permitted at the Company's option. The call provisions for the outstanding preferred stock specify various redemption prices not exceeding 108 percent of par value, plus accumulated dividends to the redemption date. NOTE 14. NUCLEAR DECOMMISSIONING COSTS Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed 27 in 1994. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the North Carolina Utilities Commission and The Public Service Commission of South Carolina have granted the Company recovery of estimated decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume each unit will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 - 2026. In accordance with a 1988 Nuclear Regulatory Commission order, during 1996, the Company expensed approximately $56.5 million which was contributed to the external funds for decommissioning costs and accrued an additional $1.6 million to the internal reserve. Nuclear units are depreciated at a rate of 4.70 percent, of which 1.61 percent is for decommissioning. The balance of the external funds as of December 31, 1996, was $362.6 million. The balance of the internal reserve as of December 31, 1996, was $207.8 million and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are currently sufficient to provide for the cost of decommissioning. NOTE 15. COMMITMENTS AND CONTINGENCIES Environmental TETCO is currently conducting PCB (polychlorinated biphenyl) assessment and cleanup programs at certain of its compressor station sites under conditions stipulated by a U.S. Consent Decree. The programs include on- and off-site assessment, installation of on-site source control equipment and groundwater monitoring wells, and on- and off-site cleanup work. TETCO expects to complete these cleanup programs during 1997. Groundwater monitoring activities will continue beyond 1997. In 1987, the Commonwealth of Kentucky instituted a suit in state court against TETCO, alleging improper disposal of PCBs at TETCO's three compressor station sites in Kentucky. This suit, which is still pending, seeks penalties for violations of Kentucky environmental statutes. The Company previously established a reserve for potential fines and penalties. In 1996, TETCO completed cleanup of these sites. The Company has also identified environmental contamination at certain sites on the PEPL and Trunkline systems and is undertaking cleanup programs at these sites. The contamination resulted from the past use of lubricants containing PCBs and the prior use of wastewater collection facilities and other on-site disposal areas. Soil and sediment testing, to date, has detected no significant off-site contamination. The Company has communicated with the Environmental Protection Agency and appropriate state regulatory agencies on these matters. Environmental cleanup programs are expected to continue until 2002. At December 31, 1996 and 1995, the Company had accrued liabilities for remaining estimated cleanup costs on the TETCO, PEPL and Trunkline systems. These cost estimates represent gross cleanup costs expected to be incurred, have not been discounted or reduced by customer recoveries and do not include fines, penalties or third-party claims. Estimated liabilities for remaining TETCO PCB cleanup costs were reduced $77.6 million in the fourth quarter 1995 as a result of lower-than-projected cleanup costs incurred on completed sites. As a result of the reduction in estimated cleanup costs, TETCO's share of the cleanup estimate was lowered, which decreased operating expenses by $33 million ($21.5 million after tax) and reduced related regulatory assets by $44.6 million. At December 31, 1996 and 1995, the Company had regulatory assets recorded representing costs to be recovered from customers. The federal and state cleanup programs are not expected to interrupt or diminish the Company's ability to deliver natural gas to customers. The Company believes the resolution of matters relating to the environmental issues discussed above will not have a material adverse effect on consolidated results of operations or financial position. Litigation In December 1996, TETCO received notification that Marathon Oil Company (Marathon) intended to commence substitution of other gas reserves, deliverability and leases for those dedicated to a certain natural gas purchase contract (the Contract) with TETCO. In TETCO's view, the tendered substitute gas reserves, deliverability and leases are not subject to the Contract and TETCO filed a declaratory judgment action seeking a ruling that Marathon's interpretation of the Contract is incorrect. Marathon filed a counterclaim seeking a declaratory judgment enforcing its interpretation of the Contract. The potential liability of the Company should TETCO be contractually obligated to purchase natural gas based upon the substitute gas reserves, 28 deliverability and leases, and the effect on transition cost recoveries pursuant to TETCO's Order 636 settlement involve numerous complex legal and factual matters which will take a substantial period of time to resolve. While this matter is in the early stages of litigation, based on information currently available to the Company, Management believes the resolution of this matter will not have a material adverse effect on financial position of the Company. In connection with a rupture and fire that occurred on TETCO's natural gas pipeline in 1994 in Edison, New Jersey, claims have been made and numerous lawsuits have been filed against TETCO and other private and governmental entities by or on behalf of hundreds of individuals and businesses. These claimants seek compensatory damages for personal injuries, property losses and/or lost business income, as well as punitive damages. The claimants include Quality Materials, Inc. (Quality), the owner of the asphalt plant where the rupture occurred. TETCO has filed a counterclaim against Quality and has settled the claims of some individuals and businesses while retaining the right to seek recovery of those settlement amounts from other defendants. The findings of an investigation of the incident by the National Transportation Safety Board indicate third-party damage to be the cause of the rupture. The Company recorded a provision in 1994 for costs related to this incident that are not recoverable under the Company's insurance policies. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or financial position of the Company. The Company and North Carolina Municipal Power Agency Number 1 and Piedmont Municipal Power Agency, two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in September 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the North Carolina Utilities Commission on January 16, 1996 and The Public Service Commission of South Carolina on January 23, 1996. As part of the settlement, the Company agreed to purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or the financial position of the Company. The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners which have been previously approved by the Company's retail regulatory commissions. (For additional information, see Note 5.) In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years will conform to the settlement agreements, which have been approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets in 1994. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. The Company is also involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Where appropriate, the Company has made accruals in accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," in order to provide for such matters. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or financial position of the Company. Nuclear Insurance The Company maintains nuclear insurance coverage in three areas: liability coverage, property, decontamination and decommissioning coverage, and extended accidental outage coverage to cover increased generating costs and/or replacement power purchases. The Company is being reimbursed by the other joint owners of the Catawba Nuclear Station for certain expenses associated with nuclear insurance premiums paid by the Company. Pursuant to the Price-Anderson Act, the Company is required to insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $8.9 billion. The maximum required private primary insurance of $200 million has been purchased along with a like amount to cover certain worker tort claims. The remaining amount, currently $8.7 billion, which will be increased by $79.3 million as each additional commercial nuclear reactor is licensed, has been provided through a mandatory industry-wide excess secondary insurance program of risk pooling. The $8.7 billion could also be reduced by $79.3 million for certain nuclear reactors that are no longer operational and may be exempted from the risk pooling insurance 29 program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the nation. If such an incident occurs and public liability damages exceed primary insurances, licensees may be assessed up to $79.3 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident. The $79.3 million amount is subject to indexing for inflation and may be subject to state premium taxes. The $79.3 million includes a surcharge of 5 percent (which is also included in the above $8.7 billion figure) if funds are insufficient to pay claims and associated costs. If retrospective premiums were to be assessed, the other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of such assessment. The Company is a member of Nuclear Mutual Limited (NML), which provides $500 million in primary property damage coverage for each of the Company's nuclear facilities. If NML's losses ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $34 million. This amount represents 5 times the Company's annual premium to NML. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NML policies applicable to Catawba. The Company is also a member of Nuclear Electric Insurance Limited (NEIL) and purchases insurance through NEIL's excess property, decontamination and decommissioning liability insurance program. NEIL provides excess insurance coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for each of the Oconee and McGuire Nuclear Stations. If losses ever exceed the accumulated funds available to NEIL for the excess property, decontamination and decommissioning liability program, the Company will be liable, on a pro rata basis, for additional assessments of up to $40 million. This amount is limited to 5 times the Company's annual premium to NEIL for excess property, decontamination and decommissioning liability insurance. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba. The Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Each unit of the McGuire and Catawba Nuclear Stations is insured for up to approximately $3.5 million per week, after a 21-week deductible period, with declining amounts per unit where more than one unit is involved in an accidental outage. The Oconee Nuclear Station units are insured for up to approximately $2.7 million, under like terms. Coverages continue at 100 percent for 52 weeks and 80 percent for the next 104 weeks. If NEIL's losses for this program ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $27 million. This amount represents 5 times the Company's annual premium to NEIL for insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to the joint ownership agreements. Future Construction Costs Projected construction and nuclear fuel costs for the Company's electric operations, both including allowance for funds used during construction, are $591.8 million and $133.5 million, respectively, for 1997. These projections are subject to periodic review and revisions. Actual construction and nuclear fuel costs incurred may vary from such estimates. Cost variances are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projected capital and investment expenditures of the natural gas transmission operations, energy services and parent and other operations are $300 million, $206.3 million, and $189 million, respectively for 1997. These projections are subject to periodic review and revisions and actual expenditures may vary significantly as business plans evolve to meet the opportunities presented by their markets. Other Commitments and Contingencies The Company has a 10% ownership interest in TEPPCO Partners, L.P., a master limited partnership (MLP) that owns and operates a petroleum products pipeline. A subsidiary partnership of the MLP had $339.5 million in First Mortgage Notes outstanding at December 31, 1996 with recourse to the general partner, a subsidiary of the Company. In the normal course of business, certain of the Company's affiliates enter into various contracts, including agreements to buy and sell natural gas or electric power; futures, swaps and options; and construction contracts, which contain certain schedule and performance requirements. Such affiliates use risk management techniques to mitigate their exposure associated with such contracts. Certain subsidiaries of the Company have guaranteed performance by such affiliates under some of these contracts. Management is of the opinion that these commitments and contingencies will not have a material adverse effect on the results of operations or the financial position of the Company. 30 NOTE 16. BENEFIT PLANS RETIREMENT PLANS The Company and its subsidiaries have defined benefit retirement plans covering most employees with minimum service requirements. The PanEnergy plan provides retirement benefits (i) for eligible employees of certain subsidiaries that are generally based on an employee's years of benefit accrual service and highest average eligible earnings, and (ii) for eligible employees of certain other subsidiaries under a cash balance formula. A cash balance plan participant accumulates a benefit based upon a percentage of current salary, which may vary with age and years of service, and interest credits. Through December 31, 1996, the Duke Power retirement plan benefits were based on an age-related formula which took into account years of benefit accrual service and the employee's highest average eligible earnings. Effective January 1, 1997, the Duke Power retirement plan was amended from a plan under which benefits were based upon a final average pay formula to a plan under which benefits are based upon a cash balance formula. The Company's policy is to fund amounts, as necessary, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan members. Net periodic pension cost for the years ended December 31, 1996, 1995 and 1994, include the following components (dollars in millions):
1996 1995 1994 ------------- -------------- ------------ Actual return on plan assets $ (302.6) $ (413.1) $ (4.0) Amount deferred for recognition 110.4 237.4 (154.4) ------------- -------------- ------------ Expected return on plan assets (192.2) (175.7) (158.4) Service cost benefit earned during the year 62.7 57.8 55.5 Interest cost on projected benefit obligation 152.8 147.9 132.3 Net amortization 6.4 3.3 4.7 ------------- ------------- ------------ Net periodic pension cost $ 29.7 $ 33.3 $ 34.1 ============= ============== ============
A reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as follows (dollars in millions): 1996 1995 -------------- ------------- Accumulated benefit obligation: Vested benefits $ (1,814.9) $ (1,652.6) Nonvested benefits (26.7) (23.8) ------------- ------------ Accumulated benefit obligation $ (1,841.6) $ (1,676.4) ============== ============= Fair market value of plan assets* $ 2,445.3 $ 2,214.1 Projected benefit obligation (2,126.4) (2,084.9) Unrecognized net experience loss 123.1 263.8 Unrecognized prior service cost reduction (45.1) (12.8) Unrecognized net asset (36.3) (40.9) ------------- ------------- Pre-funded pension cost $ 360.6 $ 339.3 ============== ============= * Principally equity and fixed income securities Assumptions used in the Company's pension accounting (reflecting weighted-averages across all plans) include:
1996 1995 1994 --------- --------- --------- Discount rate 7.50% 7.50% 8.31% Salary increase 4.80% 4.81% 5.30% Expected long-term rate of return on plan assets 9.18% 9.18% 9.18%
31 During 1995, the Company offered to certain employees an Enhanced Vested Benefits program (EVB). The Company recorded an additional one-time expense for special termination benefits associated with EVB of approximately $42.2 million, including $21.6 million of additional retirement plan costs. OTHER POSTRETIREMENT BENEFITS The Company and most of its subsidiaries provide certain health care and life insurance benefits for retired employees on a contributory and noncontributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. The Company accrues such benefit costs over the active service period of employees to the date of full eligibility for the benefits. The net unrecognized transition obligation, resulting from the implementation of accrual accounting, is being amortized over approximately 20 years. The Company is using an investment account under section 401(h) of the Internal Revenue Code, a retired lives reserve (RLR) and multiple voluntary employees' beneficiary association (VEBA) trusts under section 501(c)(9) of the Internal Revenue Code to fund postretirement benefits. These vehicles partially fund the Company's postretirement health care benefits. The Company uses the RLR, which has tax attributes similar to 401(h) funding, to partially fund its postretirement life insurance obligations. Certain subsidiaries use the VEBA trusts to fund accrued postretirement health care benefits. The same subsidiaries also use the VEBA trusts to fully fund retiree life insurance obligations based on actuarially-determined requirements. Net periodic postretirement benefit cost for the years ended December 31, 1996, 1995 and 1994, include the following components (dollars in millions):
1996 1995 1994 ------------ -------------- ------------ Actual return on plan assets $ (20.5) $ (29.6) $ (1.7) Amount deferred for recognition 4.2 16.2 (8.8) ------------ -------------- ------------ Expected return on plan assets (16.3) (13.4) (10.5) Service cost benefit earned during the year 8.4 7.6 7.6 Interest cost on accumulated postretirement benefit obligation 43.3 43.5 40.9 Net amortization and deferral 19.3 16.5 16.6 ----------- ------------- ----------- Net periodic postretirement benefit cost $ 54.7 $ 54.2 $ 54.6 ============ ============== ============
A reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as follows (dollars in millions):
1996 1995 -------------- ------------- Accumulated postretirement benefit obligation: Retirees $ (440.5) $ (436.6) Fully eligible active plan participants (42.6) (28.3) Other active plan participants (158.6) (134.6) -------------- ------------- Accumulated post retirement benefit obligation (641.7) (599.5) Fair market value of plan assets* 225.3 191.9 Unrecognized prior service cost 66.7 .7 Unrecognized net experience loss 27.0 52.7 Unrecognized transitional obligation 273.0 314.1 ------------- ------------ Accrued postretirement benefit $ (49.7) $ (40.1) ============== =============
* Principally equity and fixed income securities 32 Assumptions used in the Company's postretirement benefits accounting (reflecting weighted-averages across all plans) include:
1996 1995 1994 ---------- --------- ----------- Discount rate 7.50% 7.50% 8.34% Salary increase 4.84% 4.84% 5.25% Expected long-term rate of return on 401(h) assets 9.00% 9.00% 9.00% Expected long-term rate of return on RLR assets 6.50% 8.00% 6.50% Expected long-term rate of return on VEBA assets 9.50% 9.50% 9.50% Assumed tax rate* 39.60% 39.60% 39.60%
* Health care portion of postretirement benefits in VEBA trusts The weighted-average health care trend rate used to value the different benefits was 8.59% in 1996. This rate is expected to decrease, with a 5.5% ultimate trend rate expected to be achieved by 2001. The effect of a 1% increase in the health care trend rates for each future year is $3.6 million on the annual aggregate service and interest cost and $42.9 million on the accumulated postretirement benefit obligation at December 31, 1996. NOTE 17. COMMON STOCK On February 27, 1996, the Board of Directors authorized the Company to repurchase up to $1 billion of its common stock over the next five years. As of December 31, 1996, approximately 3.3 million shares had been repurchased for $159 million. On January 28, 1997, the Board of Directors amended the program to expressly limit the number of shares authorized for repurchase under the program, from the initiation of the program through a date two years after the consummation of the merger with PanEnergy Corp, to an amount not to exceed 15 million shares. 33 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Duke Energy Corporation Charlotte, North Carolina We have audited the consolidated balance sheets of Duke Energy Corporation and subsidiaries (the Company) as of December 31, 1996 and 1995, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. The consolidated financial statements give retroactive effect to the merger of Duke Power Company and PanEnergy Corp, which has been accounted for as a pooling of interests as described in Note 1 to the consolidated financial statements. We did not audit the balance sheet of PanEnergy Corp and subsidiaries as of December 31, 1996 and 1995, or the related statements of income, common stockholders' equity, and cash flows of PanEnergy Corp and subsidiaries for each of the three years in the period ended December 31, 1996, which statements reflect total assets of (in millions) $8,567.8 and $7,627.3 as of December 31, 1996 and 1995, respectively, and total operating revenues of (in millions), $7,536.8, $4,967.5 and $4,585.1 for the years ended December 31, 1996, 1995 and 1994, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for PanEnergy Corp and subsidiaries for 1996, 1995 and 1994, is based solely on the report of such other auditors. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. December 3, 1997 Deloitte & Touche LLP Charlotte, North Carolina -----END PRIVACY-ENHANCED MESSAGE-----