UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended | |
OR | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period from to |
For the Transition Period from to
Commission File Number | Registrant, State of Incorporation, Address and Telephone Number | I.R.S. Employer Identification No. | ||
---|---|---|---|---|
1-8809 | SCANA Corporation (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 | 57-0784499 | ||
1-3375 | South Carolina Electric & Gas Company (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 | 57-0248695 | ||
1-11429 | Public Service Company of North Carolina, Incorporated (a South Carolina corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 | 56-2128483 |
Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. SCANA Corporation Yes ý No o South Carolina Electric & Gas Company Yes ý No o Public Service Company of North Carolina, Incorporated Yes ý No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes ý No o South Carolina Electric & Gas Company Yes o No ý Public Service Company of North Carolina, Incorporated Yes o No ý
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Registrant | Description of Common Stock | Shares Outstanding at | |||
---|---|---|---|---|---|
SCANA Corporation | Without Par Value | ||||
South Carolina Electric & Gas Company | $4.50 Par Value | 40,296,147 | (a) | ||
Public Service Company of North Carolina, Incorporated | Without Par Value | 1,000 | (a) |
This combined Form 10-Q is separately filed by SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.
Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and therefore is filing this form with the reduced disclosure format allowed under General Instruction H(2).
| Page | ||||
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PART I. FINANCIAL INFORMATION | |||||
SCANA Corporation Financial Section | 3 | ||||
Item 1. | Financial Statements | ||||
Condensed Consolidated Balance Sheets as of | 4 | ||||
Condensed Consolidated Statements of Income for the Periods Ended | 6 | ||||
Condensed Consolidated Statements of Cash Flows for the Periods Ended | 7 | ||||
Condensed Consolidated Statements of Comprehensive Income for the Periods Ended | 8 | ||||
Notes to Condensed Consolidated Financial Statements | 9 | ||||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | ||||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | ||||
Item 4. | Controls and Procedures | ||||
South Carolina Electric & Gas Company Financial Section | |||||
Item 1. | Financial Statements | ||||
Condensed Consolidated Balance Sheets as of | |||||
Condensed Consolidated Statements of Income for the Periods Ended | |||||
Condensed Consolidated Statements of Cash Flows for the Periods Ended | |||||
Notes to Condensed Consolidated Financial Statements | |||||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | ||||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | ||||
Item 4. | Controls and Procedures | ||||
Public Service Company of North Carolina, Incorporated Financial Section | |||||
Item 1. | Financial Statements | ||||
Condensed Consolidated Balance Sheets as of | |||||
Condensed Consolidated Statements of | |||||
Condensed Consolidated Statements of Cash Flows for the Periods Ended | |||||
Notes to Condensed Consolidated Financial Statements | |||||
Item 2. | Management's Narrative Analysis of Results of Operations | ||||
Item 4. | Controls and Procedures | ||||
PART II. OTHER INFORMATION | |||||
Item 1. | Legal Proceedings | ||||
Item 6. Exhibits | |||||
Signatures | |||||
Exhibit Index |
SCANA CORPORATION
FINANCIAL SECTION
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
Millions of dollars | Millions of dollars | September 30, 2004 | December 31, 2003 | Millions of dollars | March 31, 2005 | December 31, 2004 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Assets | Assets | Assets | ||||||||||||||||
Utility Plant In Service | Utility Plant In Service | $ | 8,281 | $ | 7,438 | Utility Plant In Service | $ | 8,691 | $ | 8,373 | ||||||||
Accumulated Depreciation and Amortization | (2,294 | ) | (2,280 | ) | ||||||||||||||
Accumulated depreciation and amortization | Accumulated depreciation and amortization | (2,525 | ) | (2,315 | ) | |||||||||||||
5,987 | 5,158 | 6,166 | 6,058 | |||||||||||||||
Construction Work in Progress | 416 | 987 | ||||||||||||||||
Nuclear Fuel, Net of Accumulated Amortization | 26 | 42 | ||||||||||||||||
Acquisition Adjustments, Net of Accumulated Amortization | 230 | 230 | ||||||||||||||||
Construction work in progress | Construction work in progress | 174 | 432 | |||||||||||||||
Nuclear fuel, net of accumulated amortization | Nuclear fuel, net of accumulated amortization | 36 | 42 | |||||||||||||||
Acquisition adjustments | Acquisition adjustments | 230 | 230 | |||||||||||||||
Utility Plant, Net | Utility Plant, Net | 6,659 | 6,417 | Utility Plant, Net | 6,606 | 6,762 | ||||||||||||
Nonutility Property and Investments: | Nonutility Property and Investments: | Nonutility Property and Investments: | ||||||||||||||||
Nonutility property, net of accumulated depreciation of $47 and $39 | 98 | 96 | Nonutility property, net of accumulated depreciation of $54 and $50 | 103 | 104 | |||||||||||||
Assets held in trust, net—nuclear decommissioning | 48 | 44 | Assets held in trust, net—nuclear decommissioning | 50 | 49 | |||||||||||||
Other investments | 150 | 178 | Investments | 63 | 63 | |||||||||||||
Nonutility Property and Investments, Net | 296 | 318 | Nonutility Property and Investments, Net | 216 | 216 | |||||||||||||
Current Assets: | Current Assets: | Current Assets: | ||||||||||||||||
Cash and temporary investments | 191 | 117 | Cash and cash equivalents | 329 | 120 | |||||||||||||
Receivables, net of allowance for uncollectible accounts of $11 and $16 | 375 | 503 | Receivables, net of allowance for uncollectible accounts of $26 and $16 | 691 | 687 | |||||||||||||
Receivables—affiliated companies | 17 | 13 | Receivables—affiliated companies | 17 | 19 | |||||||||||||
Inventories (at average cost): | Inventories (at average cost): | |||||||||||||||||
Fuel | 186 | 147 | Fuel | 121 | 191 | |||||||||||||
Materials and supplies | 67 | 60 | Materials and supplies | 74 | 70 | |||||||||||||
Emission allowances | 10 | 6 | Emission allowances | 21 | 9 | |||||||||||||
Prepayments | 67 | 47 | Prepayments and other | 30 | 53 | |||||||||||||
Total Current Assets | 913 | 893 | Total Current Assets | 1,283 | 1,149 | |||||||||||||
Deferred Debits: | Deferred Debits: | Deferred Debits: | ||||||||||||||||
Environmental | 19 | 20 | Environmental | 17 | 18 | |||||||||||||
Pension asset, net | 281 | 270 | Pension asset, net | 290 | 285 | |||||||||||||
Other regulatory assets | 357 | 348 | Other regulatory assets | 371 | 402 | |||||||||||||
Other | 184 | 192 | Other | 160 | 164 | |||||||||||||
Total Deferred Debits | 841 | 830 | Total Deferred Debits | 838 | 869 | |||||||||||||
Total | Total | $ | 8,709 | $ | 8,458 | Total | $ | 8,943 | $ | 8,996 | ||||||||
Millions of dollars | Millions of dollars | September 30, 2004 | December 31, 2003 | Millions of dollars | March 31, 2005 | December 31, 2004 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Capitalization and Liabilities | Capitalization and Liabilities | Capitalization and Liabilities | ||||||||||||
Shareholders' Investment: | Shareholders' Investment: | Shareholders' Investment: | ||||||||||||
Common equity | $ | 2,442 | $ | 2,306 | Common equity | $ | 2,541 | $ | 2,451 | |||||
Preferred stock (Not subject to purchase or sinking funds) | 106 | 106 | Preferred stock (Not subject to purchase or sinking funds) | 106 | 106 | |||||||||
Total Shareholders' Investment | 2,548 | 2,412 | Total Shareholders' Investment | 2,647 | 2,557 | |||||||||
Preferred Stock, net (Subject to purchase or sinking funds) | Preferred Stock, net (Subject to purchase or sinking funds) | 9 | 9 | Preferred Stock, net (Subject to purchase or sinking funds) | 9 | 9 | ||||||||
Long-Term Debt, net | Long-Term Debt, net | 3,185 | 3,225 | Long-Term Debt, net | 3,073 | 3,186 | ||||||||
Total Capitalization | 5,742 | 5,646 | Total Capitalization | 5,729 | 5,752 | |||||||||
Current Liabilities: | Current Liabilities: | Current Liabilities: | ||||||||||||
Short-term borrowings | 184 | 195 | Short-term borrowings | 185 | 211 | |||||||||
Current portion of long-term debt | 258 | 202 | Current portion of long-term debt | 504 | 204 | |||||||||
Accounts payable | 185 | 288 | Accounts payable | 260 | 381 | |||||||||
Accounts payable—affiliated companies | 18 | 12 | Accounts payable—affiliated companies | 17 | 18 | |||||||||
Customer deposits | 44 | 43 | Customer deposits | 51 | 50 | |||||||||
Taxes accrued | 92 | 109 | Taxes accrued | 64 | 132 | |||||||||
Interest accrued | 56 | 55 | Interest accrued | 56 | 51 | |||||||||
Dividends declared | 43 | 41 | Dividends declared | 46 | 43 | |||||||||
Other | 85 | 78 | Other | 81 | 100 | |||||||||
Total Current Liabilities | 965 | 1,023 | Total Current Liabilities | 1,264 | 1,190 | |||||||||
Deferred Credits: | Deferred Credits: | Deferred Credits: | ||||||||||||
Deferred income taxes, net | 849 | 790 | Deferred income taxes, net | 848 | 879 | |||||||||
Deferred investment tax credits | 118 | 117 | Deferred investment tax credits | 120 | 121 | |||||||||
Asset retirement obligation—nuclear plant | 123 | 118 | Asset retirement obligation—nuclear plant | 126 | 124 | |||||||||
Non-legal asset retirement obligations | 446 | 346 | Other asset retirement obligations | 458 | 450 | |||||||||
Postretirement benefits | 140 | 135 | Postretirement benefits | 144 | 142 | |||||||||
Other regulatory liabilities | 197 | 173 | Other regulatory liabilities | 129 | 209 | |||||||||
Other | 129 | 110 | Other | 125 | 129 | |||||||||
Total Deferred Credits | 2,002 | 1,789 | Total Deferred Credits | 1,950 | 2,054 | |||||||||
Commitments and Contingencies (Note 6) | Commitments and Contingencies (Note 6) | — | — | Commitments and Contingencies (Note 6) | — | — | ||||||||
Total | Total | $ | 8,709 | $ | 8,458 | Total | $ | 8,943 | $ | 8,996 | ||||
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
| | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended March 31, | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars, except per share amounts | Millions of dollars, except per share amounts | Millions of dollars, except per share amounts | ||||||||||||||||||||
2004 | 2003 | 2004 | 2003 | 2005 | 2004 | |||||||||||||||||
Operating Revenues: | Operating Revenues: | Operating Revenues: | ||||||||||||||||||||
Electric | $ | 492 | $ | 429 | $ | 1,306 | $ | 1,121 | Electric | $ | 415 | $ | 380 | |||||||||
Gas—regulated | 162 | 155 | 776 | 775 | Gas—regulated | 460 | 426 | |||||||||||||||
Gas—nonregulated | 203 | 167 | 750 | 650 | Gas—nonregulated | 391 | 330 | |||||||||||||||
Total Operating Revenues | 857 | 751 | 2,832 | 2,546 | Total Operating Revenues | 1,266 | 1,136 | |||||||||||||||
Operating Expenses: | Operating Expenses: | Operating Expenses: | ||||||||||||||||||||
Fuel used in electric generation | 139 | 97 | 355 | 258 | Fuel used in electric generation | 128 | 95 | |||||||||||||||
Purchased power | 11 | 13 | 43 | 39 | Purchased power | 7 | 13 | |||||||||||||||
Gas purchased for resale | 300 | 262 | 1,206 | 1,127 | Gas purchased for resale | 661 | 577 | |||||||||||||||
Other operation and maintenance | 142 | 135 | 440 | 420 | Other operation and maintenance | 158 | 155 | |||||||||||||||
Depreciation and amortization | 68 | 60 | 198 | 180 | Depreciation and amortization | 245 | 63 | |||||||||||||||
Other taxes | 36 | 34 | 112 | 104 | Other taxes | 39 | 39 | |||||||||||||||
Total Operating Expenses | 696 | 601 | 2,354 | 2,128 | Total Operating Expenses | 1,238 | 942 | |||||||||||||||
Operating Income | Operating Income | 161 | 150 | 478 | 418 | Operating Income | 28 | 194 | ||||||||||||||
Other Income (Expense): | Other Income (Expense): | Other Income (Expense): | ||||||||||||||||||||
Other income (expense), including allowance for equity funds used during construction of $2, $6, $13 and $15 | (6 | ) | 16 | 27 | 48 | Other income, including allowance for equity funds used during construction of $3 and $6 | 13 | 13 | ||||||||||||||
Gain on sale of investments and assets | — | 3 | — | 60 | Interest charges, net of allowance for borrowed funds used during construction of $1 and $4 | (54 | ) | (50 | ) | |||||||||||||
Impairment of investments | (25 | ) | — | (25 | ) | (7 | ) | |||||||||||||||
Total Other Expense | (41 | ) | (37 | ) | ||||||||||||||||||
Total Other Income (Expense) | (31 | ) | 19 | 2 | 101 | |||||||||||||||||
Income (Loss) Before Income Taxes, Earnings (Losses) from Equity Method Investments and Preferred Stock Dividends | Income (Loss) Before Income Taxes, Earnings (Losses) from Equity Method Investments and Preferred Stock Dividends | (13 | ) | 157 | ||||||||||||||||||
Income Tax Expense (Benefit) | Income Tax Expense (Benefit) | (179 | ) | 55 | ||||||||||||||||||
Income Before Interest Charges, Income Taxes and Preferred Stock Dividends | 130 | 169 | 480 | 519 | ||||||||||||||||||
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $2, $3, $8 and $9 | 50 | 48 | 151 | 149 | ||||||||||||||||||
Dividend Requirement of SCE&G—Obligated Mandatorily Redeemable Preferred Securities | — | — | — | 2 | ||||||||||||||||||
Income Before Income Taxes and Preferred Stock Dividends | 80 | 121 | 329 | 368 | ||||||||||||||||||
Income Tax Expense | 24 | 35 | 108 | 120 | ||||||||||||||||||
Income Before Earnings (Losses) from Equity Method Investments and Preferred Stock Dividends | Income Before Earnings (Losses) from Equity Method Investments and Preferred Stock Dividends | 166 | 102 | |||||||||||||||||||
Earnings (Losses) from Equity Method Investments | Earnings (Losses) from Equity Method Investments | (63 | ) | 1 | ||||||||||||||||||
Income Before Preferred Stock Dividends | Income Before Preferred Stock Dividends | 56 | 86 | 221 | 248 | Income Before Preferred Stock Dividends | 103 | 103 | ||||||||||||||
Cash Dividends on Preferred Stock of Subsidiary | Cash Dividends on Preferred Stock of Subsidiary | 2 | 2 | 6 | 6 | Cash Dividends on Preferred Stock of Subsidiary | 2 | 2 | ||||||||||||||
Net Income | Net Income | $ | 54 | $ | 84 | $ | 215 | $ | 242 | Net Income | $ | 101 | $ | 101 | ||||||||
Basic and Diluted Earnings Per Share of Common Stock | Basic and Diluted Earnings Per Share of Common Stock | $ | .48 | $ | .76 | $ | 1.93 | $ | 2.18 | Basic and Diluted Earnings Per Share of Common Stock | $ | .89 | $ | .91 | ||||||||
Weighted Average Shares Outstanding (millions) | Weighted Average Shares Outstanding (millions) | 111.8 | 110.9 | 111.3 | 110.9 | Weighted Average Shares Outstanding (millions) | 112.9 | 110.9 |
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | Nine Months Ended September 30, | | Three Months Ended March 31, | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars | Millions of dollars | Millions of dollars | ||||||||||||||||||
2004 | 2003 | 2005 | 2004 | |||||||||||||||||
Cash Flows From Operating Activities: | Cash Flows From Operating Activities: | Cash Flows From Operating Activities: | ||||||||||||||||||
Net income | $ | 215 | $ | 242 | Net income | $ | 101 | $ | 101 | |||||||||||
Adjustments to reconcile net income to net cash provided from operating activities: | Adjustments to reconcile net income to net cash provided from operating activities: | |||||||||||||||||||
Depreciation and amortization | 207 | 188 | Losses from equity method investments | 63 | — | |||||||||||||||
Amortization of nuclear fuel | 16 | 18 | Depreciation and amortization | 246 | 64 | |||||||||||||||
Gain on sale of assets | — | (60 | ) | Amortization of nuclear fuel | 6 | 6 | ||||||||||||||
Hedging activities | 1 | (4 | ) | Loss on sale of assets | — | 1 | ||||||||||||||
Impairment of investments | 25 | 7 | Hedging activities | 8 | (3 | ) | ||||||||||||||
Allowance for funds used during construction | (21 | ) | (24 | ) | Allowance for funds used during construction | (4 | ) | (10 | ) | |||||||||||
Changes in certain assets and liabilities: | Cash provided (used) by changes in certain assets and liabilities: | |||||||||||||||||||
(Increase) decrease in receivables, net | 124 | 116 | Receivables, net | (2 | ) | 4 | ||||||||||||||
(Increase) decrease in inventories | (50 | ) | — | Inventories | 54 | 44 | ||||||||||||||
(Increase) decrease in prepayments | (20 | ) | 8 | Prepayments and other | 15 | (5 | ) | |||||||||||||
(Increase) decrease in pension asset | (11 | ) | (4 | ) | Pension asset | (4 | ) | (4 | ) | |||||||||||
(Increase) decrease in other regulatory assets | (24 | ) | (20 | ) | Other regulatory assets | 13 | 1 | |||||||||||||
Increase (decrease) in deferred income taxes, net | 80 | 27 | Deferred income taxes, net | (37 | ) | 1 | ||||||||||||||
Increase (decrease) in regulatory liabilities | 30 | 35 | Regulatory liabilities | (131 | ) | 3 | ||||||||||||||
Increase (decrease) in postretirement benefits obligations | 5 | 2 | Postretirement benefits obligations | 2 | 1 | |||||||||||||||
Increase (decrease) in accounts payable | (97 | ) | (82 | ) | Accounts payable | (76 | ) | (1 | ) | |||||||||||
Increase (decrease) in taxes accrued | (17 | ) | (10 | ) | Taxes accrued | (64 | ) | (30 | ) | |||||||||||
Increase (decrease) in interest accrued | 1 | — | Interest accrued | 5 | 2 | |||||||||||||||
Changes in fuel adjustment clauses | 23 | 21 | Changes in fuel adjustment clauses | 30 | 42 | |||||||||||||||
Changes in other assets | 2 | (6 | ) | Changes in other assets | 10 | 4 | ||||||||||||||
Changes in other liabilities | 17 | 9 | Changes in other liabilities | (35 | ) | (11 | ) | |||||||||||||
Net Cash Provided From Operating Activities | 506 | 463 | Net Cash Provided From Operating Activities | 200 | 210 | |||||||||||||||
Cash Flows From Investing Activities: | Cash Flows From Investing Activities: | Cash Flows From Investing Activities: | ||||||||||||||||||
Utility property additions and construction expenditures, net of AFC | (327 | ) | (558 | ) | Utility property additions and construction expenditures, net of AFC | (135 | ) | (169 | ) | |||||||||||
Proceeds from sale of investments and assets | 2 | 69 | Nonutility property additions | (3 | ) | (4 | ) | |||||||||||||
Increase in nonutility property | (15 | ) | (6 | ) | Investments in affiliates | (4 | ) | (3 | ) | |||||||||||
Investments in affiliates | (14 | ) | (11 | ) | ||||||||||||||||
Net Cash Used For Investing Activities | (142 | ) | (176 | ) | ||||||||||||||||
Net Cash Used For Investing Activities | (354 | ) | (506 | ) | ||||||||||||||||
Cash Flows From Financing Activities: | Cash Flows From Financing Activities: | Cash Flows From Financing Activities: | ||||||||||||||||||
Proceeds: | Proceeds from issuance of debt | 197 | 100 | |||||||||||||||||
Issuance of First Mortgage Bonds | — | 495 | Proceeds from issuance of common stock | 25 | 15 | |||||||||||||||
Issuance of other long-term debt | 124 | — | Repayment of debt | (2 | ) | — | ||||||||||||||
Issuance of Pollution Control Bonds | — | 36 | Repurchase of common stock | — | (4 | ) | ||||||||||||||
Issuance of common stock | 47 | 4 | Dividends on equity securities | (43 | ) | (40 | ) | |||||||||||||
Repayments: | Short-term borrowings, net | (26 | ) | (4 | ) | |||||||||||||||
Mortgage bonds | (100 | ) | (250 | ) | ||||||||||||||||
Notes, loans and SCE&G Trust I Preferred Securities | (9 | ) | (321 | ) | Net Cash Provided From Financing Activities | 151 | 67 | |||||||||||||
Pollution control bonds | — | (43 | ) | |||||||||||||||||
Net Increase In Cash and Cash Equivalents | Net Increase In Cash and Cash Equivalents | 209 | 101 | |||||||||||||||||
Cash and Cash Equivalents, January 1 | Cash and Cash Equivalents, January 1 | 120 | 117 | |||||||||||||||||
Repurchase of common stock | (4 | ) | — | |||||||||||||||||
Payment of deferred financing costs | — | (21 | ) | |||||||||||||||||
Dividends and distributions: | ||||||||||||||||||||
Common stock | (119 | ) | (113 | ) | ||||||||||||||||
Preferred stock | (6 | ) | (6 | ) | ||||||||||||||||
Short-term borrowings, net | (11 | ) | 33 | |||||||||||||||||
Net Cash Used For Financing Activities | (78 | ) | (186 | ) | ||||||||||||||||
Net Increase (Decrease) In Cash and Temporary Investments | 74 | (229 | ) | |||||||||||||||||
Cash and Temporary Investments, January 1 | 117 | 305 | ||||||||||||||||||
Cash and Temporary Investments, September 30 | $ | 191 | $ | 76 | ||||||||||||||||
Cash and Cash Equivalents, March 31 | Cash and Cash Equivalents, March 31 | $ | 329 | $ | 218 | |||||||||||||||
Supplemental Cash Flow Information: | Supplemental Cash Flow Information: | Supplemental Cash Flow Information: | ||||||||||||||||||
Cash paid for—Interest (net of capitalized interest of $8 and $9) | $ | 151 | $ | 149 | Cash paid for—Interest (net of capitalized interest of $1 and $4) | $ | 50 | $ | 47 | |||||||||||
—Income taxes | 21 | 63 | ||||||||||||||||||
—Income taxes | —Income taxes | 30 | — | |||||||||||||||||
Noncash Investing and Financing Activities: | Noncash Investing and Financing Activities: | Noncash Investing and Financing Activities: | ||||||||||||||||||
Unrealized gains (losses) on securities available for sale, net of tax | (1 | ) | 1 | Unrealized loss on securities available for sale, net of tax | — | (6 | ) |
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
| | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended March 31, | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars | Millions of dollars | Millions of dollars | ||||||||||||||||||||
2004 | 2003 | 2004 | 2003 | 2005 | 2004 | |||||||||||||||||
Net Income | Net Income | $ | 54 | $ | 84 | $ | 215 | $ | 242 | Net Income | $ | 101 | $ | 101 | ||||||||
Other Comprehensive Income (Loss), net of tax: | Other Comprehensive Income (Loss), net of tax: | Other Comprehensive Income (Loss), net of tax: | ||||||||||||||||||||
Unrealized gains (losses) on securities available for sale | 11 | 1 | (1 | ) | 1 | Unrealized losses on securities available for sale | — | (6 | ) | |||||||||||||
Unrealized gains (losses) on hedging activities | 3 | (2 | ) | 1 | (4 | ) | Unrealized gains (losses) on hedging activities | 7 | (2 | ) | ||||||||||||
Total Comprehensive Income(1) | Total Comprehensive Income(1) | $ | 68 | $ | 83 | $ | 215 | $ | 239 | Total Comprehensive Income(1) | $ | 108 | $ | 93 | ||||||||
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSSeptember 30, 2004March 31, 2005
(Unaudited)
The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (SCANA, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2003.2004. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, "Accounting"Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of March 31, 2005 the Company has recorded as of September 30, 2004, approximately $376$388 million and $643$587 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.
Millions of dollars | September 30, 2004 | December 31, 2003 | March 31, 2005 | December 31, 2004 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Accumulated deferred income taxes, net | $ | 109 | $ | 110 | $ | 126 | $ | 126 | ||||||
Under- (over-) collections—electric fuel and gas cost adjustment clauses, net | 15 | 38 | (7 | ) | 41 | |||||||||
Deferred purchased power costs | 26 | — | 23 | 26 | ||||||||||
Deferred environmental remediation costs | 19 | 20 | 17 | 18 | ||||||||||
Asset retirement obligation—nuclear decommissioning | 49 | 48 | 50 | 49 | ||||||||||
Deferred non-conventional fuel tax benefits, net | (90 | ) | (67 | ) | ||||||||||
Other asset retirement obligations | (458 | ) | (450 | ) | ||||||||||
Deferred synthetic fuel tax benefits, net | — | (97 | ) | |||||||||||
Storm damage reserve | (33 | ) | (37 | ) | (34 | ) | (33 | ) | ||||||
Franchise agreements | 59 | 62 | 57 | 58 | ||||||||||
Non-legal asset retirement obligations | (446 | ) | (346 | ) | ||||||||||
Deferred regional transmission organization costs | 13 | 14 | ||||||||||||
Other | 25 | 21 | 14 | 19 | ||||||||||
Total | $ | (267 | ) | $ | (151 | ) | $ | (199 | ) | $ | (229 | ) | ||
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under- (over-) collections—electric fuel and gas cost adjustment clauses, net, represent amounts under-collectedunder- or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or the North Carolina Utilities Commission (NCUC) during annual hearings.
Deferred purchased power costs—In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate andrepresents costs that were necessitated by outages at two of South Carolina Electric & Gas Company (SCE&G) whereby SCE&G was allowed to defer for's base load generating plants in winter 2000-2001. The SCPSC approved recovery of these costs in a future rate proceeding the portion of the purchasedbase rates over three years beginning January 2005.
power costs not allowed to be recovered through the fuel clause. In its rate application filed on July 1, 2004, SCE&G is seeking to recover these deferred purchased power costs through base rates using a three-year amortization schedule. See also Note 2.
Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G at such sites are being recovered through rates. Such costs, totaling approximately $9.3$9.5 million, are expected to be substantiallyfully recovered by the end of 2009. A portion of the costs incurred at sites owned by Public Service Company of North Carolina, Incorporated (PSNC Energy) has been recovered through rates, and management believes the remaining costs of approximately $6.6$6.4 million will be recoverable. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates at PSNC Energy are approximately $1.2$1.5 million.
Asset retirement obligation—obligation (ARO)—nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required by SFAS 143, "Accounting"Accounting for Asset Retirement Obligations."
Other asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.
Deferred non-conventionalsynthetic fuel tax benefits net, representrepresented the deferral of partnership losses and other expenses of approximately $54 million, offset by the tax benefitbenefits of those losses and expenses and accumulated synthetic fuel tax credits of approximately $144 million, associated with SCE&G's investment in two partnerships involved in converting coal to synthetic fuel. Under aIn 2005, under an accounting plan approved by the SCPSC, any tax credits generated from non-conventionalsynthetic fuel produced by the partnerships and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be appliedused to offset the capital costs of projects required to comply with legislative or regulatory actions.constructing the back-up dam at Lake Murray. See also Note 2.
The storm damage reserve represents an SCPSC approved reserve account for SCE&G capped at $50 million to be collected through rates over a period of approximately ten years.rates. The accumulated storm damage reserve can be applied to offset incremental storm damage operations and maintenance costs in excess of $2.5 million in a calendar year. For the ninethree months ended September 30, 2004, approximately $9.4 million had beenMarch 31, 2005, no amounts were drawn from this reserve account.
Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are not earning a return, but are being amortized through cost of service rates over approximately 15 years.
Non-legal asset retirement obligationsDeferred regional transmission organization costs represent net collectionscosts incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. These amounts are not earning a return, but are being amortized through depreciationcost of service rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.over approximately five years beginning in January 2005.
The SCPSC and the NCUC (collectively, state commissions) have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by a state commission. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded.
Under the SCANA Corporation Long-Term Equity Compensation Plan (the Plan), certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, "Accounting"Accounting for Stock Issued to Employees," and related
interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting"Accounting for Stock-Based Compensation" and SFAS 148, "Accounting"Accounting for Stock-Based Compensation-Transition and Disclosure."
Options, all of which were granted prior to 2003, were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates since the Plan's inception; therefore, no compensation expense has been recognized in connection with such grants. If the Company had recognized compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings per share would have been as presented below:follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2004 | 2003 | 2004 | 2003 | 2005 | 2004 | ||||||||||||
Net income—as reported (millions) | $ | 54 | $ | 84 | $ | 215 | $ | 242 | $ | 100.8 | $ | 101.2 | ||||||
Net income—pro forma (millions) | $ | 54 | $ | 83 | $ | 214 | $ | 240 | $ | 100.7 | $ | 100.9 | ||||||
Basic and diluted earnings per share—as reported | $ | .48 | $ | .76 | $ | 1.93 | $ | 2.18 | $ | .89 | $ | .91 | ||||||
Basic and diluted earnings per share—pro forma | $ | .48 | $ | .75 | $ | 1.93 | $ | 2.16 | $ | .89 | $ | .91 |
The Company also grants other forms of equity based compensation to certain employees. The value of such awards is recognized as compensation expense under APB 25. Total expense recorded for these awards was approximately $1.9 million and $2.3 million for the three months ended March 31, 2005 and 2004, respectively.
Components of net periodic benefit income or cost recorded by the Company were as follows:
| | | Other Postretirement Benefits | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Pension Benefits | ||||||||||||
Three months ended September 30 (Millions of dollars) | |||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||
Service cost | $ | 2.7 | $ | 1.9 | $ | 0.9 | $ | — | |||||
Interest cost | 9.3 | 8.3 | 2.9 | 0.5 | |||||||||
Expected return on assets | (17.7 | ) | (15.0 | ) | — | — | |||||||
Prior service cost amortization | 1.7 | 1.5 | 0.5 | (0.1 | ) | ||||||||
Transition obligation amortization | 0.2 | 0.2 | 0.8 | 0.2 | |||||||||
Amortization of actuarial loss | — | 0.2 | 0.5 | 0.1 | |||||||||
Net periodic benefit (income) cost | $ | (3.8 | ) | $ | (2.9 | ) | $ | 5.6 | $ | 0.7 | |||
| | | Other Postretirement Benefits | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Pension Benefits | ||||||||||||
Nine months ended September 30 (Millions of dollars) | ||||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||
Service cost | $ | 8.3 | $ | 7.2 | $ | 2.4 | $ | 2.5 | ||||
Interest cost | 28.1 | 27.4 | 8.7 | 8.2 | ||||||||
Expected return on assets | (53.2 | ) | (45.0 | ) | — | — | ||||||
Prior service cost amortization | 4.9 | 4.7 | 1.0 | 1.5 | ||||||||
Transition obligation amortization | 0.6 | 0.6 | 2.5 | 1.9 | ||||||||
Amortization of actuarial loss | — | 1.3 | 1.5 | 0.6 | ||||||||
Net periodic benefit (income) cost | $ | (11.3 | ) | $ | (3.8 | ) | $ | 16.1 | $ | 14.7 | ||
In May 2004, the FASB issued Staff Position (FSP) No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FSP No. 106-2), which provides guidance on how companies should account for the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") on its postretirement health care plans. To encourage employers to continue providing postretirement drug benefits, beginning in 2006 the federal government will provide non-taxable subsidy payments to employers who sponsor prescription drug benefits for retirees that are "actuarially equivalent" to the Medicare benefit. The Company has determined that its postretirement health care plans' prescription drug benefits for participants who retired prior to January 1, 1994 are actuarially equivalent to the benefits to be provided under the Act. The Company has adopted the accounting guidance of FSP No. 106-2 effective July 1, 2004. Recognition of the Act has reduced the Company's postretirement health care and life insurance plans' accumulated postretirement benefit obligation by $3.7 million and expense for the third quarter of 2004 by $0.1 million.
Other Postretirement Benefits Pension Benefits Three months ended March 31 (Millions of dollars) 2005 2004 2005 2004 Service cost $ 3.0 $ 2.8 $ 0.9 $ 0.8 Interest cost 9.5 9.1 2.8 2.9 Expected return on assets (19.1 ) (17.7 ) — — Prior service cost amortization 1.7 1.6 0.3 0.2 Transition obligation amortization 0.2 0.2 0.2 0.2 Amortization of actuarial loss — — 0.4 0.5 Net periodic benefit (income) cost $ (4.7 ) $ (4.0 ) $ 4.6 $ 4.6
Earnings per share amounts have been computed in accordance with SFAS 128, "Earnings"Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed asby dividing net income divided by the weighted average number of shares of common stock outstanding during the period, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has no securities that would have an antidilutive effect on earnings per share.
SCE&G holds two equity-method investments in two partnerships involved in converting coal to non-conventionalsynthetic fuel. SCE&G had recorded as receivables from these affiliated companies approximately $17.4$16.7 million and $13.4$18.6 million at September 30, 2004March 31, 2005 and December 31, 2003,2004, respectively. SCE&G had recorded as payables to these affiliated companies approximately $16.3$17.2 million and $12.2$17.8 million at September 30, 2004March 31, 2005 and December 31, 2003,2004, respectively. SCE&G purchased approximately $50.9 million and $38.7 million of synthetic fuel from these affiliated companies for the three months ended March 31, 2005 and 2004, respectively.
Financial Accounting Standards Board Interpretation (FIN) 47, " SFAS 123 (revised 2004),"Share-Based Payment," was issued in December 2004 and will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces SFAS 123,"Accounting for Stock-Based Compensation" and supersedes APB 25,"Accounting for Stock Issued to Employees." In April 2005, the Securities and Exchange Commission delayed the date for mandatory adoption of SFAS 123(R) until the first interim or annual reporting period of the first fiscal year beginning on or after June 15, 2005. Accordingly, the Company will adopt SFAS 123(R) in the first quarter of 2006. The Company does not expect that the initial adoption of SFAS 123(R) will have Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2. RATE AND OTHER REGULATORY MATTERS South Carolina Electric & Gas Company (SCE&G) Electric beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. In January 2003 the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 5.8% designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The rates and authorized return were effective for service rendered on and after February 1, 2003 until January 2005. SCE&G's rates are established using a cost of fuel On April 6, 2005 as part of the Gas SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the period January 1, The SCPSC allows SCE&G to recover through a billing surcharge to its On April 26, 2005, SCE&G filed an application with the SCPSC requesting a 7.09 percent increase in retail natural gas base rates, or approximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request is expected to be held and an order is expected to be issued in the fall of 2005. If approved, the new rates would go into effect in November 2005. Public Service Company of North Carolina, Incorporated (PSNC Energy) PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually. PSNC Energy's benchmark cost of gas in effect during the period January 1, On In December 1999 the NCUC issued an order approving 3. DEBT AND CREDIT FACILITIES In In March 2005 SCE&G issued $100 million first mortgage bonds having an annual interest rate of 4. RETAINED EARNINGS 5. FINANCIAL INSTRUMENTS The Company follows the guidance required by FAS 133 The Company recognized gains (losses) of approximately levels. As of At 6. COMMITMENTS AND CONTINGENCIES Reference is made to Note 10 to the consolidated financial statements appearing in In 2001 SCE&G began construction to reinforce its Lake Murray Dam in order to comply with new federal safety standards mandated by the United States Federal Energy Regulatory Commission (FERC). Construction for the project and related activities is expected to cost approximately $275 million (excluding allowance for funds used during construction (AFC)) and be completed in the second quarter of 2005. Costs incurred through The Price-Anderson Indemnification Act SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. However, if such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position. The Company maintains an environmental assessment program to identify and evaluate current and former sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate solely to regulated operations. South Carolina Electric & Gas Company At SCE&G, site assessment and cleanup costs are deferred and are being recovered through rates (see Note 2). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by the end of SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Public Service Company of North Carolina, Incorporated PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. PSNC Energy has recorded a liability and associated regulatory asset of approximately In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of the Company filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit of action for damages totaling $48 million. Post-verdict motions Upon receiving the jury verdict prior to reporting results for the third quarter of In light of the recent election order which is consistent with the interpretation above, the Company believes its accrued liability is still reasonable. However, the Company The Company is also defending another claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract of sale. A bench trial on the On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. The Company is confident of the propriety of SCE&G's actions and intends to mount a vigorous defense. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition. On May 17, 2004, the Company was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges the Company made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations. Therefore, net income is not allocated to the Electric Operations, Gas Distribution and Gas Transmission segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation. All Other includes equity method investments and other nonreportable segments. Disclosure of Reportable Segments SCANA CORPORATION The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in SCANA Corporation's (SCANA, and together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, Statements included in this discussion and analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of Electric Operations Gas Distribution On April 26, 2005, SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a 7.09 percent increase in retail natural gas base rates, or expected to In February 2005, the Natural Gas Stabilization Act of 2005 (Stabilization Act) became law in South Carolina. The Stabilization Act allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by Gas Transmission In RESULTS OF OPERATIONS Earnings Per Share Earnings per share of common stock Recognition of Synthetic Fuel Tax Credits SCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income tax credits. These synthetic fuel production facilities were placed in operation in 2000 and 2001. Under an accounting plan approved by the SCPSC in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to SCE&G, net of partnership losses and other expenses, were to be deferred until the SCPSC approved their application to offset capital costs of projects required to comply with legislative or regulatory actions. In a The level of depreciation expense and related tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account will decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during the first quarter of 2005 are as follows: Pension Income Pension income was recorded on the Company's financial statements as follows: For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. Pension income Allowance for Funds Used During Construction (AFC) AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC for the Dividends Declared The Company's Board of Directors has declared the following dividends on common stock during Electric Operations Electric Operations is comprised of the electric operations of SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company). Electric operations sales margins were as follows: Margin increased primarily due to increased retail electric Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G and Public Service Company of North Carolina, Incorporated (PSNC Energy). Gas distribution sales margins (including transactions with affiliates) were as follows: Margin increased primarily due to customer growth and increased consumption. Gas Transmission Gas Transmission is comprised of the operations of SCPC. Gas transmission sales margins (including transactions with affiliates) were as follows: Margin increased Retail Gas Marketing Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's natural gas market. Retail Gas Marketing revenues and net income were as follows: Operating revenues increased primarily as a result of Energy Marketing Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net income (loss) were as follows: Operating revenues increased primarily as a result of Other Operating Expenses Other operating expenses, which arose from the operating segments previously discussed, were as follows: Other operation and maintenance expenses increased Income Taxes Income LIQUIDITY AND CAPITAL RESOURCES The Company anticipates that its contractual cash obligations will be met through internally generated funds, the incurrence of additional short-term and long-term indebtedness and sales of additional equity securities. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company's ratio of earnings to fixed charges for the 12 months ended Cash requirements for the Company's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity The Company's issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions and the Securities and Exchange Commission. CAPITAL TRANSACTIONS In March 2005 SCE&G issued $100 million first mortgage bonds having an annual interest rate of CAPITAL PROJECTS In 2001 SCE&G began construction to reinforce its Lake Murray Dam in order to comply with new federal safety standards mandated by ENVIRONMENTAL MATTERS In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxides and sulfur dioxide emissions in order to attain mandated state levels. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates. In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule's emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates. For other information on environmental matters, see Note 6C to condensed consolidated financial statements. OTHER MATTERS Synthetic Fuel SCE&G holds 2001. Under The aggregate investment in these partnerships as of March 31, 2005 is approximately $2.9 million, and through March 31, 2005, they have generated and passed through to SCE&G approximately $144.0 million in such tax credits. As previously described at Earnings Per Share, in a January 2005 order, the The level of depreciation expense and related income tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account will decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synfuel tax credits have been utilized. The Company expects to generate enough synthetic fuel tax credits in 2005, 2006 and 2007 to cover substantially all of the costs of the dam remediation project before the synthetic fuel tax credit program expires at The ability to utilize the synthetic fuel tax credits is dependent on several factors, one of which is the average annual domestic wellhead price per barrel of crude oil as published by the U.S. Government. Under a phase-out provision included in the program, if the domestic wellhead reference price of oil per barrel falls below an inflation-adjusted benchmark range, all of the synthetic fuel tax credits that have been generated are available for use. If that price is above the benchmark range, none of the tax credits would be available. If that price falls within the benchmark range, a certain percentage of the credits would be available. The lower end of the inflation-adjusted benchmark range for 2004 was about $51 per barrel, while the upper end of that range was about $64. Since the reference price of oil for 2004 was less than $37, all of the synthetic fuel tax credits the Company had recorded and deferred through 2004 were available for use. While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. During 2005 and subject to continuing review of the estimated benchmark range and reference price of oil for 2005, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company's ability to earn synthetic fuel tax credits in the future. In order to earn these tax credits, SCANA also must be subject to a regular federal income tax liability in an amount at least equal to the credits generated in any tax year. This tax liability could be insufficient if the Company's consolidated taxable income were to be significantly reduced as the result of realizing lower income or large deductions in any tax year. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants. In March 2004, one of the partnerships, S. C. Coaltech No. 1 L.P. received a "No Change" letter from the Internal Revenue Service (IRS) related to its synthetic fuel operations for the tax year 2000. After review of testing procedures and supporting documentation and conducting an independent investigation, the IRS found that the partnership produces a qualifying fuel under section 29 of the Internal Revenue Code (IRC) and found no reason to challenge the first placed-in-service status of the facility. This letter supports the Company's position that the synthetic fuel tax credits have been properly claimed. All financial instruments held by the Company described below are held for purposes other than trading. Interest rate risk—The table below provides information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices. While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. Commodity price risk—The following table provides information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value represents quoted market prices. Expected Maturity: As of See Notes to Condensed Consolidated Financial Statements. See Notes to Condensed Consolidated Financial Statements. See Notes to Condensed Consolidated Financial Statements. The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in South Carolina Electric & Gas Company's (together with its consolidated affiliates, the Company) Annual Report on Form 10-K for the year ended December 31, 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENCO owns and operates a coal-fired electric generating station with a 615 megawatt net generating capacity (summer rating). GENCO's electricity is sold solely to SCE&G under the terms of a power purchase and related operating agreement. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO's property (carrying value of approximately The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under- (over-) collections—electric fuel and gas cost adjustment clauses, net, represent amounts Deferred purchased power costs— Deferred environmental remediation costs represent costs associated with the assessment and clean-up of manufactured gas plant (MGP) sites currently or formerly owned by SCE&G. Costs incurred by SCE&G at such sites are being recovered through rates. Such costs, totaling approximately Asset retirement Other asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists. Deferred The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a period of approximately ten years. The accumulated storm damage reserve can be applied to offset incremental storm damage operations and maintenance costs in excess of $2.5 million in a calendar year. For the Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. These amounts are not earning a return, but are being amortized through cost of service rates over approximately 15 years. The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded. SCE&G has entered into agreements with certain affiliates to purchase all gas for resale to its distribution In the first quarter 2005, the Company purchased approximately 82 miles of gas distribution pipeline from SCPC at their net book value, which totaled approximately $4.6 million. Components of net periodic benefit income or cost recorded by the Company were as follows: Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2. RATE AND OTHER REGULATORY MATTERS Electric In the January 2005 order In January 2003 the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 5.8% designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The rates and authorized return were effective for service rendered on and after February 1, 2003 until January 2005. SCE&G's rates are established using a cost of fuel On April 6, 2005 as part of the Gas SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G. SCE&G's cost of gas component in effect during the period January 1, The SCPSC allows SCE&G to recover through a billing surcharge to its On April 26, 2005, SCE&G filed an application with the SCPSC requesting a 7.09 percent increase in retail natural gas base rates, or approximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request is expected to be held and an order is expected to be issued in the fall of 2005. If approved, the new rates would go into effect in November 2005. 3. DEBT AND CREDIT FACILITIES In 4. RETAINED EARNINGS SCE&G's Restated Articles of Incorporation contain provisions that, under certain circumstances, which SCE&G considers remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At 5. COMMITMENTS AND CONTINGENCIES Reference is made to Note 10 to the consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, In 2001 SCE&G began construction to reinforce its Lake Murray Dam in order to comply with new federal safety standards mandated by the United States Federal Energy Regulatory Commission (FERC). Construction for the project and related activities is expected to cost approximately $275 million (excluding allowance for funds used during construction (AFC)) and be completed in the second quarter of 2005. Costs incurred through The Price-Anderson Indemnification Act SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. SCE&G maintains an environmental assessment program to identify and evaluate current and former sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate solely to regulated operations. At SCE&G, site assessment and cleanup costs are deferred and are being recovered through rates (see Note 2). Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for contamination. SCE&G anticipates that the remaining remediation activities will be completed by the end of SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission and distribution easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission and distribution line rights-of-way constitutes a trespass. SCE&G is confident of the propriety of its actions and intends to mount a vigorous defense. SCE&G further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition. On May 17, 2004, SCE&G was served with a purported class action lawsuit styled as Douglas E. Gressette, individually and on behalf of other persons similarly situated v. South Carolina Electric & Gas Company and SCANA Corporation. The case was filed in South Carolina's Circuit Court of Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCE&G made improper use of certain easements and rights-of-way by allowing fiber optic communication lines and/or wireless communication and rights-of-way. SCE&G intends to mount a vigorous defense and believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition. A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations , but that case has been The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. 6. SEGMENT OF BUSINESS INFORMATION The Company's reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations. Therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. Intersegment revenues were not significant. All Other includes equity method investments. The following discussion should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in South Carolina Electric & Gas Company's Statements included in this discussion and analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of Electric Operations Gas Distribution On April 26, 2005, SCE&G filed an application with the Public Service Commission of South Carolina (SCPSC) requesting a 7.09 percent increase in retail natural gas base rates, or expected to In February 2005, the Natural Gas Stabilization Act of 2005 (Stabilization Act) became law in South Carolina. The Stabilization Act allows natural gas distribution companies to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by Net Income Net income was as follows: Net income decreased In a The level of The accelerated depreciation, synthetic fuel tax credits, partnership losses and the income tax benefit arising from such losses recognized by SCE&G during the first quarter of Pension Income Pension income was recorded on For the last several years, the market value of SCANA's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. pension income Allowance for Funds Used During Construction (AFC) AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. Dividends Declared SCE&G's Electric Operations Electric Operations is comprised of the electric operations of SCE&G, Margin increased primarily due to increased retail electric Gas Distribution Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins (including transactions with affiliates) were as follows: Margin increased primarily due to customer Other Operating Expenses Other operating expenses were as follows: Other operation and maintenance expenses Interest Expense Interest expense for the quarter increased primarily due to reduced Income Taxes Income LIQUIDITY AND CAPITAL RESOURCES The Company anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. The Company's ratio of earnings to fixed charges for the 12 months ended The Company's cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of the Company to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. Company's future financial position and results of operations will be affected by additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year. The following table summarizes how SCE&G generated and used funds for property additions and construction expenditures during the The Company's issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the Securities and Exchange Commission. CAPITAL TRANSACTIONS CAPITAL PROJECTS In 2001 SCE&G began construction to reinforce its Lake Murray Dam in order to comply with new federal safety standards mandated by ENVIRONMENTAL MATTERS In March 2005 the Environmental Protection Agency (EPA) issued a final rule known as the Clean Air Interstate Rule (CAIR). CAIR requires 28 states and the District of Columbia, including South Carolina, to reduce nitrogen oxides and sulfur dioxide emissions in order to attain mandated state levels. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. Compliance plans and cost to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates. In March 2005 the EPA issued a final rule establishing a mercury emissions cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be required to comply with the mercury rule's emission caps. Compliance plans and costs to comply with the rule will be determined once the Company completes its review. Such costs will be material and are expected to be recoverable through rates. For other information on environmental matters, see Note 5C to condensed consolidated financial statements. OTHER MATTERS Synthetic Fuel SCE&G holds production facilities were placed in operation in 2000 and 2001. Under The aggregate investment in these partnerships as of March 31, 2005 is approximately $2.9 million, and through March 31, 2005, they have generated and passed through to The level of depreciation expense and related income tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of taxes. As a result, the balance of unrecovered costs in the dam remediation account will decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, they can have a significant impact on individual line items within the income statement. Depreciation on the Lake Murray Dam remediation account will be matched to available synthetic fuel tax credits on a quarterly basis until the balance in the dam remediation account is zero or until all of the available synfuel tax credits have been utilized. The Company expects to generate enough synthetic fuel tax credits in 2005, 2006 and 2007 to cover substantially all of the costs of the dam remediation project before the synthetic fuel tax credit program expires at ��The ability to utilize the synthetic fuel tax credits is dependent on several factors, one of which is the average annual domestic wellhead price per barrel of crude oil as published by the U.S. Government. Under a phase-out provision included in the program, if the domestic wellhead reference price of oil per barrel falls below an inflation-adjusted benchmark range, all of the synthetic fuel tax credits that have been generated are available for use. If that price is above the benchmark range, none of the tax credits would be available. If that price falls within the benchmark range, a certain percentage of the credits would be available. The lower end of the inflation-adjusted benchmark range for 2004 was about $51 per barrel while the upper end of that range was about $64. Since the reference price of oil for 2004 was less than $37, all of the synthetic fuel tax credits the Company had recorded and deferred through 2004 were available for use. While the benchmark price range for 2005 has been estimated at between $52 and $65 per barrel, the 2005 reference price will not be known until April 2006. During 2005 and subject to continuing review of the estimated benchmark range and reference price of oil for 2005, the Company intends to continue to record synthetic fuel tax credits as they are generated and to apply those credits quarterly to allow the recording of accelerated depreciation related to the balance in the dam remediation project account. The Company cannot predict what impact, if any, the price of oil may have on the Company's ability to earn synthetic fuel tax credits in the future. In order to earn these tax credits, SCANA also must be subject to a regular federal income tax liability in an amount at least equal to the credits generated in any tax year. This tax liability could be insufficient if SCANA's consolidated taxable income were to be significantly reduced as the result of realizing lower income or large deductions in any tax year. The availability of these synthetic fuel tax credits is also subject to coal availability and other operational risks related to the generating plants. In March 2004, All financial instruments held by the Company described below are held for purposes other than trading. Interest rate risk—The table below provides information about long-term debt issued by SCE&G which is sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity dates. Fair values for debt represent quoted market prices. While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur. As of Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and therefore is filing this form with the reduced disclosure format allowed under General Instruction H(2). See Notes to Condensed Consolidated Financial Statements. See Notes to Condensed Consolidated Financial Statements. See Notes to Condensed Consolidated Financial Statements. The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in Public Service Company of North Carolina, Incorporated's (together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, Excess deferred income taxes represent deferred income taxes recorded in prior years at a rate higher than the current statutory rate. Pursuant to a North Carolina Utilities Commission (NCUC) order, the Company is required to refund these amounts to customers through a rate decrement. Under- (over-) collections-gas cost adjustment clause, net represents amounts under- or over-collected from customers pursuant to the Company's Rider D mechanism approved by the NCUC. This mechanism allows the Company to recover all prudently incurred gas costs. Deferred environmental remediation costs represent costs associated with the assessment and The NCUC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the NCUC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to NCUC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded. Total comprehensive income was not significantly different from net income for any period reported. Accumulated other comprehensive income (loss) of the Company totaled Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2. RATE AND OTHER REGULATORY MATTERS The Company's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. The Company revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews the Company's gas purchasing practices annually. The Company's benchmark cost of gas in effect during the period January 1, On In December 1999 the NCUC issued an order approving SCANA Corporation's acquisition of the Company. As specified in the order, the Company agreed to a moratorium on general rate increases until after August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events. The Company follows the guidance required by SFAS 133 These transactions are more fully described in Note 7 to the consolidated financial statements in the Company's The Company utilizes hedging activities for natural gas purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of The Company also utilizes swap agreements to manage interest rate risk. At The Company had unused lines of credit of $125 million under a five-year revolving committed credit facility that expires in 2009. The Company is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. The Company's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. The Company has recorded a liability and associated regulatory asset of approximately Gas Distribution is the Company's only reportable segment. Gas Distribution uses operating income to measure profitability. Intersegment revenues were not significant. All Other includes equity method investments. The following discussion should be read in conjunction with Management's Narrative Analysis of Results of Operations appearing in Public Service Company of North Carolina, Incorporated's (together with its consolidated subsidiaries, PSNC Energy) Annual Report on Form 10-K for the year ended December 31, Statements included in this narrative analysis (or elsewhere in this quarterly report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in PSNC Energy's service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in PSNC Energy's accounting policies, (9) weather conditions, especially in areas served by PSNC Energy, (10) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on PSNC Energy's results of operations, (11) inflation, (12) changes in environmental regulations and (13) the other risks and uncertainties described from time to time in PSNC Energy's periodic reports filed with the United States Securities and Exchange Commission. PSNC Energy disclaims any obligation to update any forward-looking statements. Net Income and Distributions/Dividends Net income for the The nature of PSNC Energy's business is seasonal. The quarters ending PSNC Energy's Board of Directors has authorized the following distributions/dividends on common stock held by SCANA during Gas Distribution Gas distribution is comprised of the local distribution operations of PSNC Energy. Changes in the gas distribution sales margins were as follows: Gas distribution sales margin for the Other Income Other income Income Taxes Income taxes changed primarily as a result of changes in operating and other income. Capital Expansion Program and Liquidity Matters PSNC Energy's capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy's As of A complaint was filed on October 22, 2003 against In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of the subsidiaries of SCANA Corporation (SCANA) filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit Upon receiving the jury verdict prior to reporting results for the third quarter of In light of the recent election order which is consistent with the interpretation above, SCANA believes its accrued liability is still reasonable. However, SCANA SCANA is also defending another claim for $2.7 million for reimbursement of legal fees and expenses under an indemnification and hold harmless agreement in the contract of sale. A bench trial on the Each of SCANA, SCE&G and management anticipates will be resolved without material loss. The status of matters previously disclosed in their respective 2004 Annual Reports on Form 10-K Items 2, 3, 4, and 5 are not applicable. SCANA Corporation (SCANA), South Carolina Electric & Gas Company (SCE&G) and Public Service Company of North Carolina, Exhibits filed or furnished with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index. As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries, of SCE&G, for itself and its consolidated affiliates, and of PSNC Energy, for itself and its subsidiaries, have been omitted and SCANA, SCE&G and PSNC Energy agree to furnish a copy of such instruments to the Commission upon request. Pursuant to the requirements of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. The signature of each registrant shall be deemed to relate only to matters having reference to such registrant and any subsidiaries thereof. AtAccounting for Conditional Asset Retirement Obligations," was issued in March 2005 to clarify the June 30—July 1, 2004 meetingterm "conditional asset retirement" as used in SFAS 143, "Accounting for Asset Retirement Obligations." It requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the Emerging Issues Task Force (EITF),liability can be reasonably estimated. Uncertainty about the EITF reached a consensus on Issue No. 02-14, "Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock." The EITF determined that an investor should apply the equitytiming or method of accounting when it has an investment in common stock or an investment that is in-substance common stock, as defined, provided thatsettlement of a conditional asset retirement obligation would be factored into the investor has the ability to exercise significant influence over the operating and financial policiesmeasurement of the investee.liability when sufficient information exists. This consensus must be applied in reporting periods beginninginterpretation is effective no later than the end of fiscal years ending after SeptemberDecember 15, 2004. The2005. Accordingly, the Company will adopt the guidance provided by EITF Issue No. 02-14FIN 47 in the fourth quarter 2004.of 2005. The impact FIN 47 may have on the Company's financial position has not been determined but could be material. The Company does not expect that the initial adoption of FIN 47 will have a material impact on the guidanceCompany's results of operations or cash flows.anya material impact on the Company's results of operations, cash flows or financial position. At the March 2004 and November 2003 EITF meetings, the EITF reached consensus on Issue No. 03-01, "The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments." EITF Issue No. 03-01 requires that certain disclosures be made related to investments that are impaired at the balance sheet date but for which an other-than-temporary impairment has not been recognized. Guidance for evaluating whether an investment is other-than-temporarily impaired is also provided. The impairment guidance is to be applied in reporting periods beginning after June 15, 2004. The disclosure guidance is effective for annual financial statements for fiscal years ending after December 15, 2003. The Company's initial adoption on July 1, 2004 of the guidance had no impact on the Company's results of operations, cash flows or financial position.G. Reclassifications2004.2005.Electric On October 18, 2004 In a January 2005 order, the Company announced thatSCPSC granted SCE&G had entered into a stipulation and settlement agreement with the Staff of the SCPSC in connection with SCE&G's pending retail electric rate increase application that was filed on July 1, 2004. The settlement agreement is subject to review and approval by the SCPSC. If approved in its entirety, the settlement agreement would result in an overallcomposite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $51.1$41.4 million (3.57%) based on an adjusteda test year ended March 31, 2004, or about 63% of the $81.2 million (5.66%) overall revenue increase requested in the application.calculation. The settlement agreement establishes an allowedSCPSC lowered SCE&G's return on common equity in a range of 10.4%from 12.45% to an amount not to exceed 11.4%, with rates to be set based on the midpoint of that range (10.9%)at 10.7%. The settlement agreement covers allnew rates became effective in January 2005. As part of its order, the major issues addressed inSCPSC approved SCE&G's application, including recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and,Similar settlements have been negotiated with several other intervenorsUnder the accounting methodology approved by the SCPSC, current and future construction costs related to the Lake Murray Dam project are recorded in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this rate case. Hearingsaccount on this request concluded November 5, 2004, and a rate order is expected by year end. If approved, rates under such an order would go into effect January 1, 2005.accelerated basis, subject to the availability of the synthetic fuel tax credits.There can be no assurance thatIn the January 2005 order the SCPSC will approve the settlement and stipulation agreement(s), in whole or in part. Further, there can be no assurance as to the levelalso approved recovery over a five-year period of increase, if any, in retail electric rates arising from these proceedings. Testimony presented in these proceedings covered a rangeSCE&G's approximately $14 million of potential revenue adjustments, from an increase of $81.2 million, as filed by SCE&G, to a reduction of approximately $9 million supported by the Consumer Advocatecosts incurred in the hearing. In addition, atformation of the November 2004 hearing the SCPSC will consider whether to allow SCE&G to recoverGridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs. These costs that were originallypreviously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for recovery throughpossible use in the following year.clausecomponent approved by the SCPSC which may be modified periodically to reflect changes in a May 2002 order. The Consumer Advocatethe price of South Carolina (Consumer Advocate) appealed tofuel purchased by SCE&G. SCE&G's cost of fuel component in effect during the South Carolina Circuit Court (Circuit Court) the portionperiod January 1, 2004 through March 31, 2005 was as follows:Rate Per KWh Effective Date $.01678 January-April 2004 $.01821 May-December 2004 $.01764 January-March 2005 SCPSC's order related to the recoveryannual review of these purchased power costs. The Circuit Court ruled that the fuel clause only provided for the recovery of the fuel costs, included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In February 2004 the General Assembly of South Carolina clarified the definition of the fuel clause to include the total cost of power purchased. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the purchased power costs not allowed to be recovered through the fuel clause. SCE&G is seeking recovery of such costs in the current proceedings. In April 2004 the SCPSC approved SCE&G's request to increase the cost of fuel component of rates charged to electric customers from 1.678 cents$.01764 per KWh to 1.821 cents$.02256 per KWh. The increase reflects higher fuel costs projected for the period May 2004 through April 2005. The increase also provides continued recovery for under-collected actual fuel costs through February 2004. The new rates wereKWh effective as of the first billing cycle in May 2004.2005.20032004 through September 30, 2004March 31, 2005 was as follows:Rate Per Therm Effective Date $ .728.877 January-February 2003January-October 2004.928March-October 2003.877$.903 November 2003-September 20042004-March 2005 On October 27, 2004, as part of the annual review of gas costs, the SCPSC approved SCE&G's request to increase the cost of gas component from $.877 per therm to $.904 per therm effective with the first billing cycle in November 2004. commercial and residential gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce theThe billing surcharge from 3.0 cents per therm tois 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of substantially all of the balance remaining at September 30, 2004March 31, 2005 of $9.3$9.5 million.20032004 through September 30, 2004March 31, 2005 was as follows:Rate Per Therm Effective Date $ .460.600 January-February 2003January-September 2004.595$.675 March 2003October-November 2004.725April-November 2003.600$.825 December 2003-September 20042004-January 2005$.725 February-March 2005 October 1, 2004 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.600 per therm to $.675 per therm for service rendered on and after October 1, 2004. On September 30, 2004, in connection with PSNC Energy's 2004 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2004. For service rendered on and after March 1, 2004,January 21, 2005 the NCUC authorized PSNC Energy to implement decrements in its sales and transportationdefer for subsequent rate schedulesconsideration certain expenses incurred to reflect a decreasecomply with the U. S. Department of approximately $5.7 million in PSNC Energy's annual fixed gas costs as well as the current over-recoveryTransportation's Pipeline Integrity Management requirements. This accounting treatment was effective November 1, 2004. As of approximately $16.5 million. A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise wouldMarch 31, 2005 such deferrals were not be economically feasible to serve. In June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. The final phase of this project was completed and placed in service in April 2004 at a total cost of approximately $30.2 million.significant.the Company'sSCANA's acquisition of PSNC Energy. As specified in the order, PSNC Energy agreed to a moratorium on general rate increases until after August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events.February 2004 South Carolina Generating Company, Inc. (GENCO)March 2005 SCANA issued $100 million ofin senior secured promissoryunsecured floating rate medium-term notes maturing Februaryin March 2008. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 15 basis points. The proceeds from the sale, together with available cash, were used for the redemption on April 1, 2024 and bearing a fixed2005 of $200 million of floating rate medium-term notes due to mature in November 2006.5.49%. Proceeds5.25% and maturing March 1, 2035. The proceeds from this issuancethe sale of these bonds were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose. In May 2004 SCE&G borrowed $23.6 million under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million with such borrowings being repaid over ten years from the initial borrowing. At September 30, 2004 SCE&G had $22.1 millionoutstanding under the agreement. On October 22, 2004 SCE&G borrowed an additional $11.8 million under the agreement. In June 2004 the Company entered into new five-year revolving committed credit facilities totaling $650 million. These new revolving credit facilities replaced $600 million of existing committed credit facilities. SCANA, SCE&G (including South Carolina Fuel Company, Inc.) and PSNC Energy had available the following revolving credit facilities which were unused at September 30, 2004:Lines of credit (Millions) SCANA SCE&G PSNC Energy Committed Short-term $ 100 — — Long-term — $ 525 $ 125 Uncommitted 113 (1) 113 (1) — (1)Includes $113 million that either SCANA or SCE&G may use. On July 15, 2004 SCE&G retired at maturity $100 millionredemption on April 1, 2005 of first mortgage bonds. These bonds, were bearing interest at 7.70%. On October 19, 2004 SCANA retired at maturity $50 million of medium-term notes. These notes were bearing interest at 7.44%.7.625% Series due April 1, 2025.SCANA Corporation'sThe Company's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At September 30, 2004March 31, 2005 approximately $47$49 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.Investments Certain of SCANA Corporation's subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market prices, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. Debt securities and preferred stock with significant debt characteristics are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company's cost basis is other than temporary. Among the factors considered in these assessments is whether an investment's decline in value to below cost basis has continued for greater than six to nine months. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. The Company also holds investments in several partnerships and joint ventures, some of which are accounted for using the equity method. At September 30, 2004 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held investments in the following equity and debt securities.Investee Securities Basis (Millions of dollars) Magnolia Holding 6.2 million shares nonvoting common stock $ 2.1 ITC^DeltaCom 567.5 thousand shares of common stock 1.1 170.2 thousand shares series A 8% preferred stock, convertible into 3.0 million shares of common stock 13.3 Warrants to purchase 506.9 thousand shares of common stock 1.1 Knology 2.6 million shares of voting common stock 10.7 2.2 million shares of nonvoting common stock 9.0 12% senior unsecured notes due 2009 52.1 Warrants to purchase 16.5 thousand shares of common stock — Magnolia Holding Company, LLC (Magnolia Holding), holds ownership interests in several Southeastern communications companies. ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. The common shares of ITC^DeltaCom owned by SCH had a market value of $2.5 million, and the warrants owned had a market value of $0.8 million as of September 30, 2004. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and their market value is not readily determinable. Knology, Inc. (Knology) is a fully integrated provider of video, voice, data and advanced communication services to residential and business customers in the southeastern United States. In September 2004, and in accordance with the accounting policy described earlier, SCH recorded impairment losses associated with its Knology common stock investment totaling $15.0 million, net of taxes. The common shares of Knology (voting and non-voting) owned by SCH had a market value of $19.7 million as of September 30, 2004.Derivatives "Accounting"Accounting for Derivative Instruments and Hedging Activities,"as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are more fully described in Note 9 to the consolidated financial statements in SCANA's Annual Report on Form 10-K for the Company's 2003 Form 10-K.year ended December 31, 2004.$0.3$(3) million and $3.3$2 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and nine months ended September 30, 2004. The Company recognized gains (losses) of approximately $(0.4) millionMarch 31, 2005 and $5.4 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the three and nine months ended September 30, 2003.2004, respectively. These amounts were recorded in cost of gas. The Company estimates that most of the September 30, 2004March 31, 2005 unrealized gain balance of $5.6$4 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2004 and 2005 as a decrease to gas cost if market prices remain at currentSeptember 30, 2004,March 31, 2005, all of the Company's cash flow hedges will settle by their terms before the end of 2006.Option premiums and gains resulting from qualifying fair value hedges during the three and nine months ended September 30, 2004 and 2003 were insignificant and were recorded in cost of gas. As of September 30, 2004 all of the Company's fair value hedges will settle by February 2005.September 30, 2004March 31, 2005 the estimated fair value of the Company's swaps totaled $6.7$2.2 million (gain) related to combined notional amounts of $329.9$275.6 million.the Company'sSCANA's Annual Report on Form 10-K for the year ended December 31, 2003.2004. Commitments and contingencies at September 30, 2004March 31, 2005 include the following:September 30, 2004March 31, 2005 totaled approximately $223$251 million.currently(the Act) deals with public liability for a nuclear incident. Though the Act expired in 2003, existing licensees, such as the Company, are "grandfathered" under the Act until such time as it is renewed. The Act establishes the liability limit for third-partythird party claims associated with any nuclear incident at $10.8$10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $6.7 million per year.Congress failed to renew the Price-Anderson Indemnification Act when it expired in 2003. The delayed renewal has no impact on the Company due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.Authority)Authority, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $15.8 million.$9.3$9.5 million at September 30, 2004.March 31, 2005. The deferral includes the estimated costs associated with the following matters.2004,2005, with certain monitoring and retreatment activities continuing until 2007.2010. As of September 30, 2004,March 31, 2005, SCE&G had spent approximately $20.2$20.7 million to remediate the Calhoun Park site and expects to spend an additional $1.6$1.1 million. In addition, the National Park Service of the Department of the Interior made an initial demand for payment of approximately $9 million to SCE&G for certain costs and damages relating to this site. Any costs arising from these matters are expected to be recoverable through rates under South Carolina regulatory process.TwoOne of thesethe sites are currently beinghas been remediated under work plans approvedand will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination.The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three sites will be completed before 2006.in 2010. As of September 30, 2004,March 31, 2005, SCE&G had spent approximately $3.3$4.1 million related to these three sites, and expects to spend an additional $4.7$3.9 million.$6.6$6.4 million, which reflects the estimated remaining liability at September 30, 2004.March 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $1.2$1.5 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.allegesalleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 20, 2004, testimony from all parties was concluded in Circuit Court and the case was sent to the jury. On October 21, 2004, the jury issued itsan adverse verdict on this matter against the CompanySCANA for four causesare scheduledwere heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff has been ordered to be heardelect a single remedy from the weekmultiple jury awards.November 15, 2004. It is2004, it was the Company's interpretation that the damages awarded with respect to certain causes of action are overlapping.were overlapping and that the plaintiff would be required to elect a single remedy. Therefore, it iswas the Company's belief that a reasonably possible estimate of the total damages based on the amounts awarded by the jury willwould be in the range of $18—$18-$36 million. As such, in accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million pre-tax, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.believescontinues to believe that the verdict was inconsistent with the facts presented and applicable law and intends to appeal any adverse judgment ultimately entered by the Circuit Court. Basedcurrent status of this matter, and in accordance with generally accepted accounting principles,indemnification was held on January 14, 2005. A ruling has not yet been received, but is expected during the Company recorded a pre-tax charge to earnings in the thirdsecond quarter of 2004 of$18 million, $11 million after-tax, or 10 cents per share, which is the Company's reasonable estimate of the loss that is probable if the final judgment is consistent with the jury verdict. The charge and associated liability are reported in Other Income (Expense) and Current Liabilities-Other in the financial statements.2005.apparatusesequipment to transmit communications other than the Company's electricity-related internal communications. The plaintiff asserts causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. The Company believes its actions are consistent with governing law and the applicable documents granting easements and rights-of-way. The Company intends to mount a vigorous defense and believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.contained in the complaint were also the subject of a similar lawsuit that was filed and served on SCE&G but has now been dismissed. The allegations are also the subject of a purported class action lawsuit filed on or aboutin December 12, 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G). Duke Energy and Progress Energy have, but that case has been voluntarily dismissed fromby the Edwards lawsuit. The Company believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition.Plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. In addition to other environmental costs being recovered through billing surcharges, as of September 30, 2004, SCE&G is party to certain claims for costs and damages arising from The Company believes that the prior operation of a manufactured gas plant in the Calhoun Park area of Charleston, South Carolina, forwhich claims the National Park Service of the Department of the Interior has demanded payment of approximately $9 million. Any cost arising from the ultimate settlementresolution of these matters is also expected to be recoverable through rates under South Carolina regulatory processes.will not have a material adverse impact on its results of operations, cash flows or financial condition.
(Millions of dollars)Three Months Ended
September 30, 2004 External
Revenue Intersegment
Revenue Operating
Income (Loss) Net
Income (Loss) Segment
AssetsElectric Operations $ 492 $ 1 $ 168 n/a $ 5,256 Gas Distribution 114 — (11 ) n/a 1,424 Gas Transmission 48 57 3 n/a 316 Retail Gas Marketing 70 — n/a $ (1 ) 110 Energy Marketing 133 27 n/a 1 55 All Other 15 78 n/a (26 ) 675 Adjustments/Eliminations (15 ) (163 ) 1 80 873 Consolidated Total $ 857 $ — $ 161 $ 54 $ 8,709
Nine Months Ended
September 30, 2004
External
Revenue
Intersegment
Revenue
Operating
Income
Net
Income (Loss)
Segment
AssetsElectric Operations $ 1,306 $ 3 $ 385 n/a $ 5,256 Gas Distribution 622 — 38 n/a 1,424 Gas Transmission 154 238 14 n/a 316 Retail Gas Marketing 379 — n/a $ 23 �� 110 Energy Marketing 371 64 n/a — 55 All Other 44 220 n/a (23 ) 675 Adjustments/Eliminations (44 ) (525 ) 41 215 873 Consolidated Total $ 2,832 $ — $ 478 $ 215 $ 8,709
Three Months Ended
September 30, 2003
External
Revenue
Intersegment
Revenue
Operating
Income (Loss)
Net
Income
Segment
AssetsElectric Operations $ 429 $ 1 $ 162 n/a $ 4,916 Gas Distribution 114 — (15 ) n/a 1,399 Gas Transmission 41 53 3 n/a 305 Retail Gas Marketing 60 — n/a $ — 84 Energy Marketing 107 — n/a 1 50 All Other 12 65 — 1 482 Adjustments/Eliminations (12 ) (119 ) — 82 911 Consolidated Total $ 751 $ — $ 150 $ 84 $ 8,147
Nine Months Ended
September 30, 2003
External
Revenue
Intersegment
Revenue
Operating
Income
Net
Income (Loss)
Segment
AssetsElectric Operations $ 1,121 $ 4 $ 343 n/a $ 4,916 Gas Distribution 603 — 40 n/a 1,399 Gas Transmission 172 225 11 n/a 305 Retail Gas Marketing 320 — n/a $ 17 84 Energy Marketing 330 — n/a (1 ) 50 All Other 39 204 — 31 482 Adjustments/Eliminations (39 ) (433 ) 24 195 911 Consolidated Total $ 2,546 $ — $ 418 $ 242 $ 8,147 Three Months Ended
March 31, 2005 External
Revenue Intersegment
Revenue Operating
Income (Loss) Net
Income (Loss) Segment
AssetsElectric Operations $ 415 $ 1 $ (75 ) n/a $ 5,240 Gas Distribution 403 — 60 n/a 1,479 Gas Transmission 57 124 7 n/a 319 Retail Gas Marketing 239 — n/a $ 22 168 Energy Marketing 152 19 n/a (1 ) 77 All Other 16 74 n/a (63 ) 601 Adjustments/Eliminations (16 ) (218 ) 36 143 1,059 Consolidated Total $ 1,266 $ — $ 28 $ 101 $ 8,943
Three Months Ended
March 31, 2004
External
Revenue
Intersegment
Revenue
Operating
Income (Loss)
Net
Income
Segment
AssetsElectric Operations $ 380 $ 1 $ 96 n/a $ 5,134 Gas Distribution 370 2 58 n/a 1,421 Gas Transmission 54 118 6 n/a 313 Retail Gas Marketing 218 — n/a $ 20 145 Energy Marketing 112 3 n/a — 51 All Other 15 68 1 2 715 Adjustments/Eliminations (13 ) (192 ) 33 79 770 Consolidated Total $ 1,136 $ — $ 194 $ 101 $ 8,549
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS2003.2004. the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility and nonutility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in areas served by the Company's subsidiaries of SCANA, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities for the Company'sSCANA's regulated and diversified subsidiaries, (7) the results of financing efforts, (8) changes in the Company's accounting policies, (9) weather conditions, especially in areas served by the Company'sSCANA's subsidiaries, (10) performance of and marketability of the Company's investments in telecommunications companies, (11) performance of the Company'sSCANA's pension plan assets, (12)(11) inflation, (13)(12) changes in environmental regulations, (14)(13) volatility in commodity natural gas markets and (15)(14) the other risks and uncertainties described from time to time in the Company'sSCANA's periodic reports filed with the United States Securities and Exchange Commission. The CompanySCANA disclaims any obligation to update any forward-looking statements.InOn April 200421, 2005, the joint U.S.-Canada Power System Outage Task Force issued its "Final Report onU. S. House of Representatives passed the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report)Energy Policy Act of 2005 (Energy Policy Act). The Blackout Report contains 46 recommendations that, if implemented, the Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementationSome key provisions of the Blackout Report's recommendationsEnergy Policy Act that might impact the Company include the establishment of an electric reliability organization to enforce reliability standards for transmission systems, the restriction of standard market design (SMD) rulemaking by the Federal Energy Regulatory Commission (FERC) until 2006 and the provision for continued reservation of electric transmission capacity needed to serve native load customers. The Energy Policy Act also would require a numberrepeal the Public Utility Holding Company Act of actions1935, and would provide for greater regulatory oversight by legislative, regulatoryother federal and industry participants. However,state authorities. The U. S. Senate is expected to begin debate on separate energy legislation in May 2005. Differences between such legislation, if passed, and the Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in certain legislative measures (the Energy Bill), different versions of which passedPolicy Act would have to be reconciled, approved by both the House and Senate, in 2003 but have stalled in conference committee. Various provisions ofand signed by the Energy Bill related to electric reliability are being resubmitted as separate legislation (reliability legislation). It is anticipated that any reliability legislation, if passed, would make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the U.S. Federal Energy Regulatory Commission (FERC), enabling it to enact regulatory initiatives that could change, perhaps significantly, the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market and attempt to disaggregate the remaining vertically integrated utilities. In addition, the North American Electric Reliability Council (NERC) is expected to continue its initiatives to develop, establish and enforce additional standards for the grid. To that end, NERC is working closely with FERC to implement stronger reliability standards among NERC's voluntary membership. South Carolina Electric & Gas Company (SCE&G), along with other NERC members, is also working closely with NERC in these efforts. Such initiatives could be significantly influenced by any reliability legislation enacted by Congress.President before becoming law. The Company cannot predict whether Congressthe Energy Policy Act or similar legislation ultimately will enact reliabilitybe enacted, and if it is, the conditions the final legislation would impose on utilities.the extentapproximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request iswhich the other recommendations containedbe held and an order is expected to be issued in the Blackout Report will be implemented. Any actionfall of 2005. If approved, the new rates would go into effect in November 2005.Congress or initiatives by FERC and NERC could significantly impact SCE&G's access to or cost of power for its native load customers and SCE&G's marketing of power outside its service territory.the SCPSC.June 2004 the Company announced plans2005, an application to merge its two natural gas pipelineSCANA subsidiaries, into one company. Under the plan, South Carolina Pipeline Corporation (SCPC), the Company's intrastate pipeline company, would merge withand SCG Pipeline, Inc., the Company's interstate pipeline. The merged companies would operate as a single interstate pipeline company under FERC jurisdiction and would provide transportation services. If approved by FERC, the merger is expected to be completedfiled with FERC. The merger, which is subject to FERC approval, is expected to be complete in 2005.2005 or 2006. In March 2004 SCANA Energy acquired approximately 47,000 retail natural gas customers formerly served by another gas marketer in Georgia. With this transaction, SCANA Energy's total customer base represents about a 30 percent share of the 1.5 million customers in Georgia's natural gas market. SCANA Energy remains the second largest natural gas marketer in the state. In March 2004 SCANA Energy's term for serving low-income and high credit risk customers was extended by the Georgia Public Service Commission (GPSC) for an additional year (through August 31, 2005). In November 2003 the GPSC filed a petition with FERC seeking a declaratory order on the assignment of interstate capacity. That petition addressed the question of whether FERC would preempt the GPSC if a plan proposed by SCANA Energy for the assignment of Atlanta Gas Light Company's interstate capacity assets to certificated natural gas marketers was adopted by the GPSC. On April 15, 2004 FERC ruled that it continues to maintain jurisdiction and would preempt the GPSC in any plan dealing with interstate capacity assets. SCANA Energy filed a motion for reconsideration with FERC, which motion is still pending. SCANA Energy has operated successfully under the current interstate capacity plan and does not expect that FERC's ruling will have any negative impact on operations.
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2004MARCH 31, 2005
AS COMPARED TO THE CORRESPONDING PERIODSPERIOD IN 20032004 The following discussion of the results of operations of the Company includes a non-GAAP measure, GAAP-adjusted net earnings per share from operations, which excludes from net income the effects of sales of, and impairment charges related to, certain investments and the effects of a charge related to pending litigation. Management believes GAAP-adjusted net earnings per share from operations provides a meaningful representation of the Company's fundamental earnings power and can aid in analysis of period-over-period financial performance.for the periods ended September 30, 2004 and 2003 were as follows: Third Quarter Year to Date 2004 2003 2004 2003 Reported (GAAP) earnings per share $ .48 $ .76 $ 1.93 $ 2.18 Add (Deduct): Gains from sales of investments and assets — (.02 ) — (.35 ) Charge related to pending litigation .10 — .10 — Investment impairments .13 — .13 .04 GAAP-adjusted net earnings per share from operations $ .71 $ .74 $ 2.16 $ 1.87 Third Quarter 2004 vs 2003 First Quarter 2005 2004 Earnings per share $ .89 $ .91 GAAP-adjusted net earningsEarnings per share from operations decreased primarily due to increased depreciation and amortization expense of $.05, a reduction in AFC$.07 (net of $.02, higher property taxes of $.01, andincome tax benefits applied based on the January 2005 SCPSC order described below), increased operationoperations and maintenance expenses of $.04$.02, increased interest expense of $.02 and otherthe effects of $.03. This isdilution of $.02, was partially offset by favorable electric margins of $.12. GAAP earnings per share for the third quarter includes a loss of $.13 per share as a result of an impairment charge recorded on the Knology investment$.05 and a loss of $.10 resulting from a charge related to pending litigation (see Other Matters). GAAP earnings per share for 2003 includes a gain of $.02 per share in connection with the sale of ITC Holding shares and the receipt of an investment in a newly formed entity (Magnolia Holding).Year to Date 2004 vs 2003 GAAP-adjusted net earnings per share from operations increased primarily due to improved electric margins of $.46 and favorable results from nonregulated subsidiaries of $.10. These factors were partially offset by higher operation and maintenance expenses of $.07, higher property taxes of $.04, higher depreciation and amortization expense of $.09, increased labor and benefits of $.03 and lower gas margins of $.03. GAAP earnings per share year to date September 2004 includes a loss of $.13 per share as a result of an impairment charge recorded$.06. Accelerated depreciation on the Knology investmentLake Murray back-up dam and recognition of synthetic fuel tax credits and other items had no effect on net income, as discussed below.lossJanuary 2005 order, the SCPSC approved SCE&G's request to apply these synthetic fuel tax credits to offset the construction costs of $.10 resulting from a charge related to pending litigation (see Other Matters). GAAP earnings per share year to date September 2003 includes a gain of $.35 per sharethe Lake Murray Dam project beginning in connection withJanuary 2005. Under the sale of ITC Holding sharesaccounting methodology approved by the SCPSC, current and the receipt of an investment interest in a newly formed entity (Magnolia Holding) in May 2003. In the second quarter of 2003 the Company also recorded an impairment charge of $.04 per sharefuture construction costs related to the Knology investment.project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.Factors Increasing (Decreasing)
Net Income (millions) Deferred
prior to 2005 Added
1st Quarter
2005 Recognized
1st Quarter
2005 Recognized in Statement of Income: Depreciation and amortization expense — $ (169.7 ) $ (169.7 ) Income tax benefits: From synthetic fuel tax credits $ 134.2 9.8 144.0 From accelerated depreciation — 64.9 64.9 From partnership losses 22.5 1.8 24.3 Total income tax benefits 156.7 76.5 233.2 Losses from Equity Method Investments (58.7 ) (4.8 ) (63.5 ) Impact on Net Income $ — Third Quarter Year to Date First Quarter Millions of dollars Millions of dollars Millions of dollars 2004 2003 2004 2003 2005 2004 Income Statement Impact: Income Statement Impact: Income Statement Impact: Reduction in (component of) employee benefit costs $ 0.4 $ 0.5 $ 2.2 $ (1.7 ) Reduction in employee benefit costs $ 1.2 $ 1.1 Other income 3.2 2.1 8.1 6.0 Other income 3.0 2.5 Balance Sheet Impact: Balance Sheet Impact: Balance Sheet Impact: Reduction in (component of) capital expenditures 0.1 0.2 0.7 (0.4 ) Reduction in capital expenditures 0.4 0.3 Component of amount due to (from) Summer Station co-owner 0.1 0.1 0.3 (0.1 ) Component of amount due to Summer Station co-owner 0.1 0.1 Total Pension Income Total Pension Income $ 3.8 $ 2.9 $ 11.3 $ 3.8 Total Pension Income $ 4.7 $ 4.0 in 2004for the first quarter of 2005 increased compared to the corresponding periodsperiod in 20032004 primarily as a result of a more favorable investment market.ninethree months ended September 30, 2004March 31, 2005 decreased slightly primarily due to completion of the Jasper County Electric Generating SystemStation in May 2004, offset by2004. Included in the equity portion of AFC resulting fromis approximately $2.8 million, which was accrued as a result of the January 2005 SCPSC rate order related to construction costs for the back-up dam at Lake Murray Dam Project.Murray.2004:2005:Declaration Date Dividend Per Share Record Date Payment Date February 19, 200417, 2005 $ .365.39 March 10, 20042005 April 1, 20042005April 29, 2004May 5, 2005 $ .365.39 June 10, 20042005 July 1, 2004July 29, 2004$.365September 10, 2004October 1, 2004October 29, 2004$.365December 10, 2004January 1, 2005 Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 Operating revenues $ 491.9 14.7 % $ 429.0 $ 1,306.4 16.4 % $ 1,121.3 Less: Fuel used in generation 139.2 43.8 % 96.8 354.7 37.7 % 257.6 Purchased power 10.7 (16.4 )% 12.8 43.2 10.8 % 39.0 Margin $ 342.0 7.1 % $ 319.4 $ 908.5 10.2 % $ 824.7 Third Quarter 2004 vs 2003 Margin increased due to $10.6 million from off-system sales, $9.8 million due to customer growth and consumption and $2.2 million due to favorable weather.Year to Date 2004 vs 2003Millions of dollars 2005 First Quarter
% Change 2004 Operating revenues $ 415.3 9.3 % $ 379.9 Less: Fuel used in generation 127.8 34.0 % 95.4 Purchased power 6.6 (48.0 )% 12.7 Margin $ 280.9 3.4 % $ 271.8 base rates that went into effect in February 2003,January 2005 for a total impact of $7.1$14.4 million an additional $22.7and customer growth and increase consumption of $1.8 million, which was partially offset by $5.4 million due to favorableunfavorable weather $34.5and by $1.1 million fromrelated to decreased off-system sales and $18.9 million due to customer growth and consumption.sales. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 Operating revenues $ 114.0 0.3 % $ 113.7 $ 622.0 3.4 % $ 602.6 Less: Gas purchased for resale 80.7 (0.4 )% 81.0 442.7 6.8 % 414.7 Margin $ 33.3 1.8 % $ 32.7 $ 179.3 (4.1 )% $ 187.9 Third Quarter 2004 vs 2003Millions of dollars 2005 First Quarter
% Change 2004 Operating revenues $ 402.8 8.4 % $ 371.7 Less: Gas purchased for resale 292.8 10.8 % 264.2 Margin $ 110.0 2.3 % $ 107.5 Year to Date 2004 vs 2003 Margin decreased primarily due to a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in operations and maintenance expense) and an unfavorable competitive position of natural gas relative to alternate fuels of $0.4 million at SCE&G, and a decline in customer usage per degree-day of $4.0 million, partially offset by customer growth and consumption of $2.3 million at PSNC Energy. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 Operating revenues $ 105.9 11.6 % $ 94.9 $ 392.1 (1.3 )% $ 397.4 Less: Gas purchased for resale 93.2 10.7 % 84.2 351.6 (3.0 )% 362.6 Margin $ 12.7 18.7 % $ 10.7 $ 40.5 16.4 % $ 34.8 Third Quarter 2004 vs 2003Millions of dollars 2005 First Quarter
% Change 2004 Operating revenues $ 181.0 5.1 % $ 172.3 Less: Gas purchased for resale 165.9 5.2 % 157.7 Margin $ 15.1 3.4 % $ 14.6 primarilyslightly due to higher transportation and reservation revenue as a result of new firm transportation customers.volumes.Year to Date 2004 vs 2003 Margin increased primarily due to higher transportation and reservation revenue as a result of new firm transportation customers. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 Operating revenues $ 70.1 16.6 % $ 60.1 $ 379.1 18.4 % $ 320.3 Net income $ (0.5 ) * $ 0.1 $ 23.2 38.9 % $ 16.7 *Greater than 100%Third Quarter 2004 vs 2003Millions of dollars 2005 First Quarter
% Change 2004 Operating revenues $ 238.8 9.7 % $ 217.7 Net income $ 22.3 8.3 % $ 20.6 increased volumes and higher average retail prices due to higher gas costs. Net income decreased primarily due to increased operating and marketing expenses of $1.7 million, partially offset by a reduction in bad debt expense of $0.8 million.Year to Date 2004 vs 2003 Operating revenues increased primarily as a result of increased volumes and higher average retail prices due to highercommodity gas costs. Net income increased primarily due to higher margins of $10.5 million, partially offset by increased bad debt expense of $1.3 millioncustomer growth and increased operating and marketing expenses of approximately $2.7 million.consumption. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 2005 First Quarter
% Change 2004 Operating revenues $ 159.7 49.5 % $ 106.8 $ 434.1 31.6 % $ 329.8 $ 170.6 48.1 % $ 115.2 Net income (loss) $ 1.2 71.4 % $ 0.7 $ 0.2 * $ (1.0 ) Net loss $ (0.8 ) * $ (0.5 ) Greater than 100%Not meaningfulThird Quarter 2004 vs 2003increasedhigher commodity prices which offset decreased volumes. Net income increaseddecreased primarily due to lower operating expenses.Year to Date 2004 vs 2003 Operating revenues increased primarily as a result of increased volumes. Net income increased primarily due to improved gas margins in the first and second quarters of $1.5 million partially offset by higher bad debt expense of $0.5 million.margins. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 2005 First Quarter
% Change 2004 Other operation and maintenance $ 142.1 5.4 % $ 134.8 $ 440.2 4.8 % $ 420.0 $ 159.0 2.9 % $ 154.6 Depreciation and amortization 68.3 13.6 % 60.1 197.6 9.6 % 180.3 244.8 * 62.7 Other taxes 35.6 2.0 % 34.9 112.8 7.7 % 104.7 38.2 (1.6 )% 38.8 Total $ 246.0 7.1 % $ 229.8 $ 750.6 6.5 % $ 705.0 $ 442.0 * $ 256.1 Third Quarter 2004 vs 2003primarily due to other operating costs (primarily bad debt of $2.7 million) related to increased laborcustomers in the Retail Gas Marketing segment, and benefit costsdue to nuclear and fossil maintenance expenses of $4.6 million, offset by decreases in winter storm expenses of $2.5 million and $3.1 million of increased operating expenses at the generation plants.employee benefit expenses. Depreciation and amortization increased $5.0approximately $169.7 million due to accelerated depreciation of the back-up dam at Lake Murray (previously discussed atRecognition of Synthetic Fuel Tax Credits) and increased $6.0 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $2.7$3.7 million due to normal net property changes.Year to Date 2004 vs 2003 Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $8.2 million, 2004 winter storm restoration expenses of $2.5 million, increased expenses at electric generation plants of $5.9 million, increased bad debt of $2.8 million and gas marketing and customer billing costs of $4.4 million, partially offset by a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in gas margin) and increased pension income of $3.8 million. Depreciation and amortization increased $8.4 million due to the completion of the Jasper County Electric Generating Station and $7.6 million due to normal net property changes. Other taxes increased primarily due to increased property taxes.Other IncomeThird Quarter 2004 vs 2003 Other income, including AFC, decreased primarily due to the impairment charge of the Company's Knology investment and the charge associated with pending litigation (as discussed at Earnings Per Share and Other Matters), and due to a decrease in AFC upon completion of the Jasper County Electric Generating Station in May 2004, which was somewhat offset by increased AFC resulting from expenditures on the Lake Murray Dam Project.Year to Date 2004 vs 2003 Other income, including AFC, decreased primarily due to the monetization and valuation of the Company's Knology investment and the charge associated with pending litigation (as discussed at Earnings Per Share and Other Matters), and due to a decrease in AFC upon completion of the Jasper County Electric Generating Station completed in May 2004, which was somewhat offset by increased AFC resulting from expenditures on the Lake Murray Dam Project.taxestax expense for the quarter and nine months ended September 30, 2004March 31, 2005 decreased primarilyby approximately $233.2 million as a result of changes in Other Income aspreviously discussed at Earnings Per Share.Recognition of Synthetic Fuel Tax Credits.September 30, 2004March 31, 2005 was 2.67.1.91.orand gas, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.relief, if requested. On October 18, 2004 In a January 2005 order, the SCPSC granted SCE&G announced that it had entered into a stipulation and settlement agreement with the Staff of the SCPSC in connection with SCE&G's pending retail electric rate increase application that was filed on July 1, 2004. The settlement agreement is subject to review and approval by the SCPSC. If approved in its entirety, the settlement agreement would result in an overallcomposite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $51.1$41.4 million (3.57%) based on an adjusteda test year ended March 31, 2004, or about 63% of the $81.2 million (5.66%) overall revenue increase requested in the application.calculation. The settlement agreement establishes an allowedSCPSC lowered SCE&G's return on common equity in a range of 10.4%from 12.45% to an amount not to exceed 11.4%, with rates to be set based on the midpoint of that range (10.9%)at 10.7%. The settlement agreement covers allnew rates became effective in January 2005. As part of its order, the major issues addressed inSCPSC approved SCE&G's application, including recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Similar settlements have been negotiated with several otherMurray (as previously discussed atRecognition of Synthetic Fuel Tax Credits). The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.intervenors in this rate case. Hearings on this request concluded November 5, 2004, and a rate order is expected by year end. If approved, rates under such an order would go into effect January 1, 2005. There can be no assurance that the SCPSC will approve the settlement and stipulation agreement(s), in whole or in part. Further, there can be no assurance as to the level of increase, if any, in retail electric rates arising from these proceedings. Testimony presented in these proceedings covered a range of potential revenue adjustments, from an increase of $81.2 million, as filed by SCE&G, to a reduction of approximately $9 million supported by the Consumer Advocate in the hearing. �� The following table summarizes how the Company generated and used funds for property additions and construction expenditures during the ninethree months ended September 30, 2004March 31, 2005 and 2003:2004: Nine Months Ended
September 30, Three Months Ended
March 31, Millions of dollars 2004 2003 2005 2004 Net cash provided from operating activities $ 506 $ 463 $ 200 $ 210 Net cash used for financing activities (78 ) (186 ) Cash provided from sale of investments and assets 2 69 Cash and temporary investments available at the beginning of the period 117 305 Net cash provided from financing activities 151 67 Cash and cash equivalents available at the beginning of the period 120 117 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $ (327 ) $ (558 )
$
(135
)
$
(169
)Funds used for nonutility property additions (15 ) (6 ) (3 ) (4 ) Funds used for investments (14 ) (11 ) (4 ) (3 ) In June 2004 the Company entered into new five-year revolving committed credit facilities totaling $650 million. These new revolving credit facilities replaced $600 million of existing committed credit facilities. SCANA, SCE&G (including South Carolina Fuel Company, Inc.) and PSNC Energy had available the following revolving credit facilities which were unused at September 30, 2004:Lines of Credit (Millions) SCANA SCE&G PSNC Energy Lines of credit: Committed Short-term $ 100 — — Long-term — $ 525 $ 125 Uncommitted 113 (1) 113 (1) — (1)Includes $113 million that either SCANA or SCE&G may use. At September 30, 2004 SCE&G (including South Carolina Fuel Company, Inc.) and PSNC Energy had $165 million and $19 million, respectively, in short-term borrowings at weighted average interest rates of 1.80% and 1.87%, respectively.On February 11, 2004 GENCOIn March 2005 SCANA issued $100 million ofin senior secured promissoryunsecured floating rate medium-term notes maturing Februaryin March 2008. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 15 basis points. The proceeds from the sale, together with available cash, were used for the redemption on April 1, 2024 and bearing a fixed2005 of $200 million of floating rate medium-term notes due to mature in November 2006.5.49%. Proceeds5.25% and maturing March 1, 2035. The proceeds from this issuancethe sale of these bonds were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose. Effective Maythe redemption on April 1, 2004 shares of SCANA's common stock purchased on behalf of participants in the SCANA Investor Plus Plan, Stock Purchase-Savings Plan and Director Compensation and Deferral Plan are being purchased directly from SCANA rather than on the open market. SCANA estimates that these original issue purchases will result in the issuance of approximately two million new shares of common stock and provide approximately $65 million in additional common stock equity on an annual basis. In addition, since March 31, 2004 SCANA has not purchased outstanding shares of common stock on the open market. In May 2004 SCE&G borrowed $23.6 million under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million with such borrowings being repaid over ten years from the initial borrowing. At September 30, 2004 SCE&G had $22.1 million outstanding under the agreement. On October 22, 2004 SCE&G borrowed an additional $11.8 million under the agreement. On July 15, 2004 SCE&G retired at maturity $100 million2005 of first mortgage bonds. These bonds, were bearing interest at 7.70%. On October 19, 2004 SCANA retired at maturity $50 million of medium-term notes. These notes were bearing interest at 7.44%.7.625% Series due April 1, 2025. In May 2004 SCE&G's 875 megawatt Jasper County Electric Generating Station began commercial operation. The $450 million facility includes three natural gas combustion-turbine generators and one steam-turbine generator. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder is included in the rate case previously discussed.the United States Federal Energy Regulatory Commission (FERC).FERC. Construction for the project and related activities is expected to cost approximately $275 million (excluding AFC) and be completed in the second quarter of 2005. Costs incurred through September 30, 2004March 31, 2005 totaled approximately $223$251 million. See alsoAs discussed below under Other Matters, the previous rate case discussion. ConstructionCompany expects that substantially all of SCPC's South System Loop was completed in March 2004 at a costthe costs of approximately $21 million. This pipeline stretches 38.3 miles from SCG Pipeline's connection with SCE&G's Jasper County Electric Generating Station to Yemassee in Hampton County, South Carolina, providing a new gas supply source to SCPC's current system.the Lake Murray Dam project will be covered by synthetic fuel tax credits.Nuclear Station In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through August 6, 2042.two equity-method investments in two partnerships involved in converting coal to non-conventionalsynthetic fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of September 30, 2004 is approximately $3 million, and through September 30, 2004, they have generated and passed to SCE&G approximately $124 million inThese synthetic fuel tax credits. At September 30, 2004 SCE&G has recorded on its balance sheet $90 million net deferred tax benefits, which includes the effects of partnership losses. In addition, Primesouth, Inc, a non-regulated subsidiary of SCANA, operates a synthetic fuel facility for a third partyproduction facilities were placed in operation in 2000 and receives management fees, royalties and expense reimbursements related to these services. Primesouth does not benefit directly from any synfuel tax credits.aan accounting plan approved by the SCPSC anyin June 2000, the synthetic fuel tax credits generated by the partnerships and ultimately passed through to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and willwere to be deferred and will be applieduntil the SCPSC approved their application to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1Acondensed consolidated financial statements. As discussed previously,SCPSC approved SCE&G's rate case seeks SCPSC approvalrequest to apply current and anticipated netthese synthetic fuel tax credits to offset the costconstruction costs of constructing the back-upLake Murray Dam project beginning in January 2005. Under the accounting methodology approved by the SCPSC, current and future construction costs related to the project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.Lake Murray.the end of 2007. Section 29 of the IRC provides for the reduction of synthetic fuel tax credits for any calendar year in which the average annual wellhead price of oil exceeds an inflation-adjusted base price per barrel (as defined in the IRC, and currently estimated to be approximately $52), up to a maximum price spread (as defined in the IRC, and currently estimated to be in the range of $12-$13), at which point the credits would be completely phased-out. The Company cannot predict what impact, if any, the price of oil may have on the Company's ability to earn synthetic fuel tax credits in the future.Pending Litigation In 1999 an unsuccessful bidder for the purchase of certain propane gas assets of the Company filed suit against SCANA in Circuit Court, seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 20, 2004, testimony from all parties was concluded in Circuit Court and the case was sent to the jury. On October 21, 2004, the jury issued its verdict on this matter against the Company for four causes of action for damages totaling $48 million. Post-verdict motions are scheduled to be heard the week of November 15, 2004. It is the Company's interpretation that the damages awarded with respect to certain causes of action are overlapping. Therefore, it is the Company's belief that a reasonably possible estimate of the total damages based on the amounts awarded by the jury will be in the range of $18—$36 million. However, the Company believes that the verdict was inconsistent with the facts presented and applicable law and intends to appeal any adverse judgment by the Circuit Court. Based on the current status of this matter, and in accordance with generally accepted accounting principles, the Company recorded a pre-tax charge to earnings in the third quarter of 2004 of $18 million, $11 million after-tax, or 10 cents per share, which is the Company's reasonable estimate of the loss that is probable if the final judgment is consistent with the jury verdict. The charge and associated liability are reported in Other Income (Expense) and Current Liabilities—Other in the financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk Expected Maturity Date As of September 30, 2004
Millions of dollars 2004 2005 2006 2007 2008 There-
After Total Fair
ValueLiabilities Long-Term Debt: Fixed Rate ($) 58.0 193.6 174.4 68.6 158.6 2,640.9 3,294.1 3,375.6 Average Fixed Interest Rate (%) 7.65 7.39 8.50 6.96 6.13 6.24 6.46 Variable Rate ($) 200.0 200.0 200.0 Average Variable Interest Rate (%) 2.16 2.16 Interest Rate Swaps: Pay Variable/Receive Fixed ($) 54.3 3.2 3.2 28.2 118.2 122.8 329.9 6.7 Average Pay Interest Rate (%) 7.55 5.17 5.17 5.59 4.24 4.06 4.85 Average Receive Interest Rate (%) 7.64 8.75 8.75 7.11 5.89 6.51 6.57 Expected Maturity Date As of March 31, 2005
Millions of dollars
Liabilities 2005 2006 2007 2008 2009 There-
After Total Fair
Value Long-Term Debt: Fixed Rate($) 193.6 174.4 68.6 158.6 143.6 2,632.8 3,371.6 3,404.5 Average Fixed Interest Rate(%) 7.39 8.50 6.96 8.12 8.21 6.20 6.58 Variable Rate($) 200.0 100.0 300.0 300.0 Average Variable Interest Rate(%) 3.24 3.11 3.20 n/a Interest Rate Swaps: Pay Variable/Receive Fixed($) 3.2 3.2 28.2 118.2 3.2 119.6 275.6 (2.2 ) Average Pay Interest Rate(%) 5.74 5.74 6.04 4.73 5.74 4.46 4.78 Average Receive Interest Rate(%) 8.75 8.75 7.11 5.89 8.75 6.45 6.36 At September 30, 2004 the Company held investments in the 12% senior unsecured notes (due 2009) of Knology, Inc. the cost basis of which is approximately $52.1 million. As these notes are not broadly traded, determination of their fair value is not practical. Futures Contracts Futures Contracts Options
Purchased Call
(Long) ($) Long ($) Short ($) 2004 2005 Futures Contracts Options
Purchased Call
(Long)($) Settlement Price(a) 7.19 7.22 7.86 7.80 Contract Amount 17.1 3.3 Strike Price(a) 8.61 Fair Value 20.7 3.8 Contract Amount 20.0
2005
Settlement Price(a) 7.55 7.98 Contract Amount 21.9 2.5 24.0 9.6 Strike Price(a ) 6.80 Fair Value 27.3 3.0 29.2 10.5 Contract Amount 35.9
2006
Settlement Price(a) 6.98 — 8.73 Contract Amount 0.5 — 1.3 Fair Value 0.8 — 1.8 Equity price risk—Investments in telecommunications companies' equity securities (excluding preferred stock with significant debt characteristics) are carried at market value or, if market value is not readily determinable, at cost. The carrying value of the Company's investments in such securities totaled $25.0 million at September 30, 2004. A temporary decline in value of ten percent would result in a $2.5 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of Other Comprehensive Income (Loss). An other than temporary decline in value of ten percent would result in a $2.5 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.
Item 4. Controls and ProceduresSeptember 30, 2004March 31, 2005 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of September 30, 2004March 31, 2005 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2004March 31, 2005 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
FINANCIAL SECTION
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)Millions of dollars Millions of dollars September 30,
2004 December 31,
2003 Millions of dollars March 31,
2005 December 31,
2004 Assets Assets Assets Utility Plant In Service Utility Plant In Service $ 7,020 $ 6,207 Utility Plant In Service $ 7,412 $ 7,096 Accumulated Depreciation and Amortization (1,900 ) (1,907 ) Accumulated depreciation and amortization Accumulated depreciation and amortization (2,138 ) (1,934 ) 5,120 4,300 5,274 5,162 Construction Work in Progress 369 951 Nuclear Fuel, Net of Accumulated Amortization 26 42 Construction work in progress Construction work in progress 157 417 Nuclear fuel, net of accumulated amortization Nuclear fuel, net of accumulated amortization 36 42 Utility Plant, Net Utility Plant, Net 5,515 5,293 Utility Plant, Net 5,467 5,621 Nonutility Property and Investments: Nonutility Property and Investments:
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation 25 19 Nonutility property, net of accumulated depreciation 26 27 Assets held in trust, net—nuclear decommissioning 48 44 Assets held in trust, net—nuclear decommissioning 50 49 Other investments 6 6 Investments 6 6 Nonutility Property and Investments, Net 79 69 Nonutility Property and Investments, Net 82 82 Current Assets: Current Assets:
Current Assets:
Cash and temporary investments 12 56 Cash and cash equivalents 17 20 Receivables, net 234 238 Receivables, net of allowance for uncollected accounts of $1 and $1 264 267 Receivables—affiliated companies 22 61 Receivables—affiliated companies 21 19 Inventories (at average cost): Inventories (at average cost): Fuel 35 35 Fuel 60 35 Materials and supplies 61 54 Materials and supplies 67 64 Emission allowances 10 6 Emission allowances 21 9 Prepayments 26 20 Prepayments 40 30 Total Current Assets 400 470 Total Current Assets 490 444 Deferred Debits: Deferred Debits:
Deferred Debits:
Environmental 11 11 Environmental 9 11 Pension asset, net 281 270 Pension asset, net 290 285 Due from affiliates—pension and postretirement benefits 22 20 Due from affiliates—pension and postretirement benefits 23 23 Other regulatory assets 334 333 Other regulatory assets 361 376 Other 155 162 Other 135 138 Total Deferred Debits 803 796 Total Deferred Debits 818 833 Total Total $ 6,797 $ 6,628 Total $ 6,857 $ 6,980 Millions of dollars Millions of dollars September 30,
2004 December 31,
2003Millions of dollars March 31,
2005 December 31,
2004Capitalization and Liabilities Capitalization and Liabilities Capitalization and Liabilities Shareholders' Investment: Shareholders' Investment:
Shareholders' Investment:
Common equity $ 2,147 $ 2,043 Common equity $ 2,201 $ 2,164 Preferred stock (Not subject to purchase or sinking funds) 106 106 Preferred stock (Not subject to purchase or sinking funds) 106 106 Total Shareholders' Investment 2,253 2,149 Total Shareholders' Investment 2,307 2,270 Preferred Stock, net (Subject to purchase or sinking funds) Preferred Stock, net (Subject to purchase or sinking funds) 9 9 Preferred Stock, net (Subject to purchase or sinking funds) 9 9 Long-Term Debt, net Long-Term Debt, net 1,976 2,010 Long-Term Debt, net 1,976 1,981 Total Capitalization Total Capitalization 4,238 4,168 Total Capitalization 4,292 4,260 Minority Interest Minority Interest 77 100
Minority Interest
80
81 Current Liabilities: Current Liabilities:
Current Liabilities:
Short-term borrowings 165 140 Short-term borrowings 183 153 Current portion of long-term debt 198 142 Current portion of long-term debt 298 198 Accounts payable 71 104 Accounts payable 77 106 Accounts payable—affiliated companies 61 134 Accounts payable—affiliated companies 99 113 Customer deposits 25 25 Customer deposits 27 26 Taxes accrued 85 118 Taxes accrued 30 152 Interest accrued 37 39 Interest accrued 37 35 Dividends declared 38 43 Dividends declared 40 38 Other 34 42 Other 40 50 Total Current Liabilities 714 787 Total Current Liabilities 831 871 Deferred Credits: Deferred Credits:
Deferred Credits:
Deferred income taxes, net 761 707 Deferred income taxes, net 712 744 Deferred investment tax credits 116 114 Deferred investment tax credits 118 119 Asset retirement obligation—nuclear plant 123 118 Asset retirement obligation—nuclear plant 126 124 Non-legal asset retirement obligations 360 265 Other asset retirement obligations 369 363 Due to affiliates—pension and postretirement benefits 14 15 Due to affiliates—pension and postretirement benefits 13 14 Postretirement benefits 140 135 Postretirement benefits 144 142 Other regulatory liabilities 185 164 Other regulatory liabilities 109 198 Other 69 55 Other 63 64 Total Deferred Credits 1,768 1,573 Total Deferred Credits 1,654 1,768 Commitments and Contingencies (Note 5) Commitments and Contingencies (Note 5) — —
Commitments and Contingencies (Note 5)
—
— Total Total $ 6,797 $ 6,628
Total
$
6,857
$
6,980
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited) Three Months Ended
September 30, Nine Months Ended
September 30,Millions of dollars 2004 2003 2004 2003 Operating Revenues: Electric $ 493 $ 430 $ 1,310 $ 1,125 Gas 62 54 275 259 Total Operating Revenues 555 484 1,585 1,384 Operating Expenses: Fuel used in electric generation 139 97 355 258 Purchased power 11 13 43 39 Gas purchased for resale 51 44 217 194 Other operation and maintenance 103 96 315 303 Depreciation and amortization 57 49 164 148 Other taxes 32 31 102 95 Total Operating Expenses 393 330 1,196 1,037 Operating Income 162 154 389 347 Other Income, Including Allowance for Equity Funds Used During Construction of $2, $5, $11 and $14 5 9 19 24 Income Before Interest Charges, Minority Interest, Income Taxes and Preferred Stock Dividends 167 163 408 371 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $2, $3, $7 and $8 34 33 104 101 Dividend Requirement of Company—Obligated Mandatorily Redeemable Preferred Securities — — — 2 Income Before Minority Interest, Income Taxes and Preferred Stock Dividends 133 130 304 268 Minority Interest 2 2 5 5 Income Before Taxes and Preferred Stock Dividends 131 128 299 263 Income Tax Expense 46 40 104 88 Net Income 85 88 195 175 Preferred Stock Cash Dividends Declared 2 2 6 6 Earnings Available for Common Shareholder $ 83 $ 86 $ 189 $ 169 Three Months Ended
March 31, Millions of dollars 2005 2004 Operating Revenues: Electric $ 416 $ 381 Gas 157 146 Total Operating Revenues 573 527
Operating Expenses:
Fuel used in electric generation 128 95 Purchased power 7 13 Gas purchased for resale 121 111 Other operation and maintenance 108 108 Depreciation and amortization 233 52 Other taxes 35 35 Total Operating Expenses 632 414
Operating Income (Loss)
(59
)
113
Other Income (Expense):
Other Income, including allowance for equity funds used during construction of $3 and $5 6 6 Interest charges, net of allowance for borrowed funds used during construction of $1 and $3 (37 ) (35 ) Total Other Expense (31 ) (29 )
Income (Loss) Before Income Taxes, Earnings (Losses) from Equity Method Investments, Minority Interest and Preferred Stock Dividends
(90
)
84
Income Tax Expense (Benefit) (207 ) 29
Income Before Earnings (Losses) from Equity Method Investments, Minority Interest and Preferred Stock Dividends
117
55
Earnings (Losses) from Equity Method Investments (64 ) 1 Minority Interest (1 ) (2 )
Net Income
52
54
Preferred Stock Cash Dividends Declared 2 2 Earnings Available for Common Shareholder $ 50 $ 52
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Nine Months Ended
September 30, Three Months Ended
March 31, Millions of dollars Millions of dollars Millions of dollars 2004 2003 2005 2004 Cash Flows From Operating Activities: Cash Flows From Operating Activities: Cash Flows From Operating Activities: Net income $ 52 $ 54 Net income $ 195 $ 175 Adjustments to reconcile net income to net cash provided from operating activities: Adjustments to reconcile net income to net cash provided from operating activities: Losses from equity method investments 64 — Minority interest 5 5 Minority interest 1 2 Depreciation and amortization 164 148 Depreciation and amortization 233 52 Amortization of nuclear fuel 16 18 Amortization of nuclear fuel 6 6 Allowance for funds used during construction (18 ) (22 ) Allowance for funds used during construction (4 ) (8 ) Changes in certain assets and liabilities: Cash provided (used) by changes in certain assets and liabilities: (Increase) decrease in receivables, net 43 7 Receivables, net 1 27 (Increase) decrease in inventories (11 ) 30 Inventories (40 ) (4 ) (Increase) decrease in prepayments (6 ) 4 Prepayments (10 ) (5 ) (Increase) decrease in pension asset (11 ) (4 ) Pension asset (5 ) (4 ) (Increase) decrease in other regulatory assets (23 ) (20 ) Other regulatory assets 14 2 Increase (decrease) in deferred income taxes, net 52 34 Deferred income taxes, net (47 ) 1 Increase (decrease) in regulatory liabilities 27 33 Regulatory liabilities (133 ) 4 Increase (decrease) in postretirement benefits obligations 5 2 Postretirement benefits obligations 2 1 Increase (decrease) in accounts payable (106 ) (29 ) Accounts payable (1 ) (12 ) Increase (decrease) in taxes accrued (33 ) 3 Taxes accrued (122 ) (53 ) Increase (decrease) in interest accrued (2 ) 4 Interest accrued 2 1 Changes in fuel adjustment clauses 30 26 Changes in fuel adjustment clauses 5 32 Changes in other assets (5 ) (1 ) Changes in other assets 3 (1 ) Changes in other liabilities 17 4 Changes in other liabilities (14 ) 1 Net Cash Provided From Operating Activities 339 417 Net Cash Provided From Operating Activities 7 96 Cash Flows From Investing Activities: Cash Flows From Investing Activities:
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (281 ) (496 ) Utility property additions and construction expenditures, net of AFC (117 ) (150 ) Increase in nonutility property (5 ) — Nonutility property additions — (1 ) Proceeds from sale of assets 2 — Investments in affiliates (4 ) (3 ) Investments in affiliates (14 ) (11 ) Net Cash Used For Investing Activities (121 ) (154 ) Net Cash Used For Investing Activities (298 ) (507 ) Cash Flows From Financing Activities: Cash Flows From Financing Activities:
Cash Flows From Financing Activities:
Proceeds: Proceeds from issuance of debt 97 100 Issuance of First Mortgage Bonds — 495 Repayment of debt (2 ) — Pollution Control Bonds — 36 Dividends on equity securities (37 ) (43 ) Other long-term debt 124 — Distribution to parent — (27 ) Distributions from parent 21 57 Distribution from parent 23 — Repayments: Short-term borrowings, net 30 51 Mortgage Bonds (100 ) (250 ) Pollution Control Bonds — (43 ) Net Cash Provided From Financing Activities 111 81 Other long-term debt (2 ) (11 )
Net Increase (Decrease) In Cash and Cash Equivalents
Net Increase (Decrease) In Cash and Cash Equivalents
(3
)
23
Cash and Cash Equivalents, January 1 Cash and Cash Equivalents, January 1 20 56 SCE&G Trust I Preferred Securities — (50 ) Payment of deferred financing costs — (21 ) Dividends and distributions: Common stock (118 ) (115 ) Preferred stock (6 ) (6 ) Distribution to parent (29 ) — Short-term borrowings, net 25 18 Net Cash Provided From (Used For) Financing Activities (85 ) 110 Net Increase (Decrease) In Cash and Temporary Investments (44 ) 20 Cash and Temporary Investments, January 1 56 23 Cash and Temporary Investments, September 30 $ 12 $ 43 Cash and Cash Equivalents, March 31 Cash and Cash Equivalents, March 31 $ 17 $ 79 Supplemental Cash Flow Information: Supplemental Cash Flow Information: Supplemental Cash Flow Information: Cash paid for—Interest (net of capitalized interest of $7 and $8) $ 100 $ 90 Cash paid for—Interest (net of capitalized interest of $1 and $3) $ 37 $ 35 —Income taxes —Income taxes 30 8 —Income taxes 48 —
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSSeptember 30, 2004March 31, 2005
(Unaudited)2003.2004. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported. The Company adopted Financial Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46), "Consolidation"Consolidation of Variable Interest Entities", effective January 1, 2004, which requires an enterprise's consolidated financial statements to include entities in which the enterprise has a controlling financial interest. South Carolina Electric and Gas Company (SCE&G) has determined that it has a controlling financial interest in South Carolina Generating Company, Inc. (GENCO) under the criteria of FIN 46,and South Carolina Fuel Company, Inc. (Fuel Company), and accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and South CarolinaFuel Company. The equity interests in GENCO and Fuel Company Inc. Prior period amounts have been restated to reflect the adoption of FIN 46. The consolidation resulted in an increase of approximately $327 million in net assets reflected in the condensed consolidated balance sheet as of September 30, 2004. The equity interest in GENCO isare held solely by SCANA Corporation, the Company's parent. Accordingly, GENCO's and Fuel Company's equity and results of operations are reflected as a minority interest in the Company's condensed consolidated financial statements, and the adoption of FIN 46 therefore had no impact on the Company's equity, net earnings or cash flows.statements.$77$80 million) serves as collateral for its long-term borrowings. "Accounting"Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of March 31, 2005 the Company has recorded as of September 30, 2004,approximatelyapproximately $345$370 million and $545$478 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.Millions of dollars September 30,
2004 December 31,
2003 March 31,
2005 December 31,
2004 Accumulated deferred income taxes, net $ 103 $ 104 $ 121 $ 121 Under- (over-) collections—electric fuel and gas cost adjustment clauses, net 9 39 7 31 Deferred purchased power costs 26 — 23 26 Deferred environmental remediation costs 11 11 9 11 Asset retirement obligation—nuclear decommissioning 49 48 50 49 Deferred non-conventional fuel tax benefits, net (90 ) (67 ) Other asset retirement obligations (368 ) (363 ) Deferred synthetic fuel tax benefits, net — (97 ) Storm damage reserve (33 ) (37 ) (34 ) (33 ) Franchise agreements 59 62 57 58 Non-legal asset retirement obligations (360 ) (265 ) Deferred regional transmission organization costs 13 14 Other 26 20 14 19 Total $ (200 ) $ (85 ) $ (108 ) $ (164 ) under-collectedunder- or over-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings.In April 2004 therepresents costs that were necessitated by outages at two of South Carolina Electric & Gas Company (SCE&G)'s base load generating plants in winter 2000-2001. The SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G was allowed to defer for recovery in a future rate proceeding the portion of the purchased powerthese costs not allowed to be recovered through the fuel clause. In its rate application filed on July 1, 2004, SCE&G is seeking to recover these deferred purchased power costs throughin base rates using a three-year amortization schedule. See also Note 2.over three years beginning in January 2005.$9.3$9.5 million, are expected to be substantiallyfully recovered by the end of 2009.obligation—obligation (ARO)—nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required by SFAS 143, "Accounting"Accounting for Asset Retirement Obligations."non-conventionalsynthetic fuel tax benefits net representrepresented the deferral of partnership losses and other expenses of approximately $54 million, offset by the tax benefitbenefits of those losses and expenses and accumulated synthetic fuel tax credits of approximately $144 million associated with SCE&G's investment in two partnerships involved in converting coal to synthetic fuel. Under aIn 2005, under an accounting plan approved by the SCPSC, any tax credits generated from non-conventionalsynthetic fuel produced by the partnerships and ultimately passed through to SCE&G, net of partnership losses and other expenses, have been and will be deferred and will be appliedused to offset the capital costs of projects required to comply with legislative or regulatory actions.constructing the back-up dam at Lake Murray. See also Note 2.ninethree months ended September 30, 2004, approximately $9.4 million had beenMarch 31, 2005, no amounts were drawn from this reserve account.Non-legal asset retirement obligationsDeferred regional transmission organization costs represent net collectionscosts incurred by SCE&G in the United States Federal Energy Regulatory Commission (FERC)-mandated formation of GridSouth. The project was suspended in 2002. These amounts are not earning a return, but are being amortized through depreciationcost of service rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.over approximately five years beginning January 2005.customers.customers and to purchase electric energy. SCE&G purchases all of its natural gas requirementsfor resale and electric generation from South Carolina Pipeline Corporation (SCPC). SCE&G and had approximately $17.5$38.3 million and $39.5$49.5 million payable to SCPC for such gas purchases at September 30, 2004March 31, 2005 and December 31, 2003,2004, respectively.The CompanySCE&G holds two equity-method investments in two partnerships involved in converting coal to non-conventionalsynthetic fuel. The Company had recorded as receivables from these affiliated companies for these investments approximately $17.4$16.7 million and $13.4$18.6 million at September 30, 2004March 31, 2005 and December 31, 2003,2004, respectively. The CompanySCE&G had recorded as payables to these affiliated companies approximately $16.3$17.2 million and $12.2$17.8 million at September 30, 2004March 31, 2005 and December 31, 2003,2004, respectively. SCE&G purchased approximately $50.9 million and $38.7 million of synthetic fuel from these affiliated companies for the three months ended March 31, 2005 and 2004, respectively. Other Postretirement Benefits Pension Benefits Three months ended September 30 (Millions of dollars) 2004 2003 2004 2003 Service cost $ 2.7 $ 1.9 $ 0.9 $ — Interest cost 9.3 8.3 2.9 0.5 Expected return on assets (17.7 ) (15.0 ) — — Prior service cost amortization 1.7 1.5 0.5 (0.1 ) Transition obligation amortization 0.2 0.2 0.8 0.2 Amortization of actuarial loss — 0.2 0.5 0.1 Amount attributable to Company affiliates (0.5 ) (0.3 ) (1.5 ) (0.2 ) Net periodic benefit (income) cost $ (4.3 ) $ (3.2 ) $ 4.1 $ 0.5 Other Postretirement Benefits
Pension Benefits
Nine months ended September 30 (Millions of dollars) 2004 2003 2004 2003 Service cost $ 8.3 $ 7.2 $ 2.4 $ 2.5 Interest cost 28.1 27.4 8.7 8.2 Expected return on assets (53.2 ) (45.0 ) — — Prior service cost amortization 4.9 4.7 1.0 1.5 Transition obligation amortization 0.6 0.6 2.5 1.9 Amortization of actuarial loss — 1.3 1.5 0.6 Amount attributable to Company affiliates (1.3 ) (1.3 ) (4.4 ) (4.0 ) Net periodic benefit (income) cost $ (12.6 ) $ (5.1 ) $ 11.7 $ 10.7 Other Postretirement Benefits Pension Benefits Three months ended March 31 (Millions of dollars) 2005 2004 2005 2004 Service cost $ 3.0 $ 2.8 $ 0.9 $ 0.8 Interest cost 9.5 9.1 2.8 2.9 Expected return on assets (19.1 ) (17.7 ) — — Prior service cost amortization 1.7 1.6 0.3 0.2 Transition obligation amortization 0.2 0.2 0.2 0.2 Amortization of actuarial loss — — 0.4 0.5 Amount attributable to Company affiliates (0.4 ) (0.4 ) (1.2 ) (1.3 ) Net periodic benefit (income) cost $ (5.1 ) $ (4.4 ) $ 3.4 $ 3.3 In May 2004, Financial Accounting Standards Board Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations," was issued in March 2005 to clarify the FASB issued Staff Position (FSP) No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FSP No. 106-2), which provides guidance on how companies should accountterm "conditional asset retirement" as used in SFAS 143, "Accounting for Asset Retirement Obligations." It requires that a liability be recognized for the impactfair value of a conditional asset retirement obligation when incurred, if the fair value of the Medicare Prescription Drug, Improvement and Modernization Actliability can be reasonably estimated. Uncertainty about the timing or method of 2003 (the "Act")settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly, the Company will adopt FIN 47 in the fourth quarter of 2005. The impact FIN 47 may have on its postretirement health care plans. To encourage employers to continue providing postretirement drug benefits, beginning in 2006 the federal government will provide non-taxable subsidy payments to employers who sponsor prescription drug benefits for retirees that are "actuarially equivalent" to the Medicare benefit.Company's financial position has not been determined but could be material. The Company has determineddoes not expect that its postretirement health care plans' prescription drug benefits for participants who retired prior to January 1, 1994 are actually equivalent to the benefits to be provided under the Act. The Company has adopted the accounting guidanceinitial adoption of FSP No. 106-2 effective July 1, 2004. Recognition of the Act has reducedFIN 47 will have a material impact on the Company's postretirement health care and life insurance plans' accumulated postretirement benefit obligation by $3.7 million and expense for the third quarterresults of 2004 by $0.1 million.E. Reclassificationsoperations or cash flows.2004.2005.On October 18, 2004In a January 2005 order, the SCPSC granted SCE&G announced that it had entered into a stipulation and settlement agreement with the Staff of the SCPSC in connection with SCE&G's pending retail electric rate increase application that was filed on July 1, 2004. The settlement agreement is subject to review and approval by the SCPSC. If approved in its entirety, the settlement agreement would result in an overallcomposite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $51.1$41.4 million (3.57%) based on an adjusteda test year ended March 31, 2004, or about 63% of the $81.2 million (5.66%) overall revenue increase requested in the application.calculation. The settlement agreement establishes an allowedSCPSC lowered SCE&G's return on common equity in a range of 10.4%from 12.45% to an amount not to exceed 11.4%, with rates to be set based on the midpoint of that range (10.9%)at 10.7%. The settlement agreement covers allnew rates became effective in January 2005. As part of its order, the major issues addressed inSCPSC approved SCE&G's application, including recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and, beginning in January 2005, the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Similar settlements have been negotiated with several other intervenorsUnder the accounting methodology approved by the SCPSC, current and future construction costs related to the Lake Murray Dam project are recorded in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this rate case. Hearingsaccount on this request concluded November 5, 2004, and a ratean accelerated basis, subject to the availability of the synthetic fuel tax credits. is expected by year end. If approved, rates under such an order would go into effect January 1, 2005. There can be no assurance that the SCPSC will approve the settlement and stipulation agreement(s), in whole or in part. Further, there can be no assurance as to the levelalso approved recovery over a five-year period of increase, if any, in retail electric rates arising from these proceedings. Testimony presented in these proceedings covered a rangeSCE&G's approximately $14 million of potential revenue adjustments, from an increase of $81.2 million, as filed by SCE&G, to a reduction of approximately $9 million supported by the Consumer Advocatecosts incurred in the hearing. In addition, atformation of the November 2004 hearing the SCPSC will consider whether to allow SCE&G to recoverGridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs. These costs that were originallypreviously deferred. As a part of its order, the SCPSC extended through 2010 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, in the event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without additional approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for recovery throughpossible use in the following year.clausecomponent approved by the SCPSC which may be modified periodically to reflect changes in a May 2002 order. The Consumer Advocatethe price of South Carolina (Consumer Advocate) appealed tofuel purchased by SCE&G. SCE&G's cost of fuel component in effect during the South Carolina Circuit Court (Circuit Court) the portionperiod January 1, 2004 through March 31, 2005 was as follows:Rate Per KWh Effective Date $.01678 January-April 2004 $.01821 May-December 2004 $.01764 January-March 2005 SCPSC's order related to the recoveryannual review of these purchased power costs. The Circuit Court ruled that the fuel clause only provided for the recovery of the fuel costs, included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In February 2004 the General Assembly of South Carolina clarified the definition of the fuel clause to include the total cost of power purchased. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the purchased power costs not allowed to be recovered through the fuel clause. SCE&G is seeking recovery of such costs in the current proceedings. In April 2004 the SCPSC approved SCE&G's request to increase the cost of fuel component of rates charged to electric customers from 1.678 cents$.01764 per KWh to 1.821 cents$.02256 per KWh. The increase reflects higher fuel costs projected for the period May 2004 through April 2005. The increase also provides continued recovery for under-collected actual fuel costs through February 2004. The new rates wereKWh effective as of the first billing cycle in May 2004.2005.20032004 through September 30, 2004March 31, 2005 was as follows:Rate Per Therm Effective Date $ .728.877 January-February 2003January-October 2004.928March-October 2003.877$.903 November 2003-September 20042004-March 2005 On October 27, 2004, as part of the annual review of gas costs, the SCPSC approved SCE&G's request to increase the cost of gas component from $.877 per therm to $.904 per therm effective with the first billing cycle in November 2004. commercial and residential gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce theThe billing surcharge from 3.0 cents per therm tois 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of substantially all of the balance remaining at September 30, 2004March 31, 2005 of $9.3$9.5 million.February 2004 GENCOMarch 2005 SCE&G issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixedfirst mortgage bonds having an annual interest rate of 5.49%. Proceeds5.25% and maturing March 1, 2035. The proceeds from this issuancethe sale of these bonds were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose. In May 2004 SCE&G borrowed $23.6 million under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million with such borrowings being repaid over ten years from the initial borrowing. At September 30, 2004 SCE&G had $22.1 million outstanding under the agreement. On October 22, 2004 SCE&G borrowed an additional $11.8 million under the agreement. In June 2004 the Company entered into new five-year revolving committed credit facilities totaling $525 million. These new revolving credit facilities replaced $475 million in existing committed credit facilities. On July 15, 2004 SCE&G retired at maturity $100 millionredemption on April 1, 2005 of first mortgage bonds. These bonds, were bearing interest at 7.70%.7.625% Series due April 1, 2025.September 30, 2004March 31, 2005 approximately $47$49 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.2003.2004. Commitments and contingencies at September 30, 2004March 31, 2005 include the following:September 30, 2004March 31, 2005 totaled approximately $223$251 million.currently(the Act) deals with public liability for a nuclear incident. Though the Act expired in 2003, existing licensees, such as the Company, are "grandfathered" under the Act until such time as it is renewed. The Act establishes the liability limit for third-partythird party claims associated with any nuclear incident at $10.8$10.5 billion. Each reactor licensee is currently liable for up to $100.6 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $67.1 million per incident, but not more than $6.7 million per year.Congress failed to renew the Price-Anderson Indemnification Act when it expired in 2003. The delayed renewal has no impact on SCE&G due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.Authority)Authority, the one-third owner of Summer Station) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $15.8 million.IfHowever, if such an incident were to occur, it would have a material adverse impact on SCE&G'sthe Company's results of operations, cash flows and financial position.$9.3$9.5 million at September 30, 2004.March 31, 2005. The deferral includes the estimated costs associated with the following matters.2004,2005, with certain monitoring and retreatment activities continuing until 2007.2010. As of September 30, 2004,March 31, 2005, SCE&G had spent approximately $20.2$20.7 million to remediate the Calhoun Park site and expects to spend an additional $1.6$1.1 million. In addition, the Department of the Interior made an initial demand for payment of approximately $9 million to SCE&G for certain costs and damages relating to this site. Any costs arising from these matters are expected to be recoverable through rates under South Carolina regulatory process.TwoOne of thesethe sites are currently beinghas been remediated under work plans approvedand will undergo routine monitoring until released by the South Carolina Department of Health and Environmental Control (DHEC). SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination.The other sites are currently being investigated under work plans approved by DHEC. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006.in 2010. As of September 30, 2004,March 31, 2005, SCE&G had spent approximately $3.3$4.1 million related to these three sites, and expects to spend an additional $4.7$3.9 million.apparatusesequipment to transmit communications other than SCE&G's electricity-related internal communications. The plaintiff asserts causes of action for unjust enrichment, trespass, injunction and declaratory judgment. The plaintiff did not assert a specific dollar amount for the claims. SCE&G believes its actions are consistent with governing law and the applicable documents granting easementscontained in the complaint were also the subject of a similar lawsuit that was filed and served on SCE&G but has now been dismissed. The allegations are also the subject of a purported class action lawsuit filed on or aboutin December 12, 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G). Duke Energy and Progress Energy havevoluntarily dismissed fromby the Edwards lawsuit. The Company believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition.Plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. In addition to other environmental costs being recovered through billing surcharges, as of September 30, 2004, SCE&G is party to certain claims for costs and damages arising from The Company believes that the prior operation of a manufactured gas plant in the Calhoun Park area of Charleston, South Carolina, for which claims the National Park Service of the Department of the Interior has demanded payment of approximately $9 million. Any cost arising from the ultimate settlementresolution of these matters is also expected to be recoverable through rates under South Carolina regulatory processes.will not have a material adverse impact on its results of operations, cash flows or financial condition.
Disclosure of Reportable Segments
(Millions of Dollars)Three Months Ended September 30, 2004 2003 External
Revenue Operating
Income (Loss) Segment
Assets External
Revenue Segment
Assets Operating
Income (Loss)Electric Operations $ 493 $ 168 $ 5,256 $ 430 $ 163 $ 4,929 Gas Distribution 62 (4 ) 340 54 (8 ) 319 Adjustments/Eliminations — (2 ) 1,201 — (1 ) 1,122 Consolidated Total $ 555 $ 162 $ 6,797 $ 484 $ 154 $ 6,370
Nine Months Ended September 30,
2004
2003 External
Revenue Operating
Income (Loss) Segment
Assets External
Revenue Operating
Income (Loss) Segment
AssetsElectric Operations $ 1,310 $ 385 $ 5,256 $ 1,125 $ 343 $ 4,929 Gas Distribution 275 6 340 259 5 319 Adjustments/Eliminations — (2 ) 1,201 — (1 ) 1,122 Consolidated Total $ 1,585 $ 389 $ 6,797 $ 1,384 $ 347 $ 6,370 Three Months Ended March 31, 2005 2004 External
Revenue Operating
Income
(Loss) Net
Income
(Loss) Segment
Assets External
Revenue Operating
Income
(Loss) Net
Income
(Loss) Segment
AssetsElectric Operations $ 416 $ (75 ) n/a $ 5,240 $ 381 $ 97 n/a $ 5,080 Gas Distribution 157 17 n/a 359 146 16 n/a 325 All Other — — $ (64 ) 3 — — $ 1 3 Adjustments/Eliminations — (1 ) 114 1,255 — — 51 1,256 Consolidated Total $ 573 $ (59 ) $ 50 $ 6,857 $ 527 $ 113 $ 52 $ 6,664
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
SOUTH CAROLINA ELECTRIC & GAS COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS(together(SCE&G, and together with its consolidated affiliates, the Company) Annual Report on Form 10-K for the year ended December 31, 2003.2004. the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) regulatory actions or changes in the utility regulatory environment, (3) current and future litigation, (4) changes in the economy, especially in the Company'sSCE&G's service territory, (5) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (6) growth opportunities, (7) the results of financing efforts, (8) changes in the Company's accounting policies, (9) weather conditions, especially in areas served by the Company,SCE&G, (10) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on the Company'sSCE&G's results of operations, (11) inflation, (12) changes in environmental regulations and (13) the other risks and uncertainties described from time to time in the Company'sSCE&G's periodic reports filed with the United States Securities and Exchange Commission. The Company disclaims any obligation to update any forward-looking statements.InOn April 200421, 2005, the joint U.S.-Canada Power System Outage Task Force issued its "Final Report onU.S. House of Representatives passed the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report)Energy Policy Act of 2005 (Energy Policy Act). The Blackout Report contains 46 recommendations that, if implemented, the Task Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementationSome key provisions of the Blackout Report's recommendationsEnergy Policy Act that might impact the Company include the establishment of an electric reliability organization to enforce reliability standards for transmission systems, the restriction of standard market design (SMD) rulemaking by the Federal Energy Regulatory Commission (FERC) until 2006 and the provision for continued reservation of electric transmission capacity needed to serve native load customers. The Energy Policy Act also would require a numberrepeal the Public Utility Holding Company Act of actions1935, and would provide for greater regulatory oversight by legislative, regulatoryother federal and industry participants. However,state authorities. The U.S. Senate is expected to begin debate on separate energy legislation in May 2005. Differences between such legislation, if passed, and the Blackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in certain legislative measures (the Energy Bill), different versions of which passedPolicy Act would have to be reconciled, approved by both the House and Senate, in 2003 but have stalled in conference committee. Various provisions ofand signed by the Energy Bill related to electric reliability are being resubmitted as separate legislation (reliability legislation). It is anticipated that any reliability legislation, if passed, would make reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the U.S. Federal Energy Regulatory Commission (FERC), enabling it to enact regulatory initiatives that could change, perhaps significantly, the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market and attempt to disaggregate the remaining vertically integrated utilities. In addition, the North American Electric Reliability Council (NERC) is expected to continue its initiatives to develop, establish and enforce additional standards for the grid. To that end, NERC isworking closely with FERC to implement stronger reliability standards among NERC's voluntary membership. SCE&G, along with other NERC members, is also working closely with NERC in these efforts. Such initiatives could be significantly influenced by any reliability legislation enacted by Congress.President before becoming law. The Company cannot predict whether Congressthe Energy Policy Act or similar legislation ultimately will enact reliabilitybe enacted, and if it is, the conditions the final legislation would impose on utilities.the extentapproximately $28 million based on an adjusted test year ended December 31, 2004. A hearing on this request iswhich the other recommendations containedbe held and an order is expected to be issued in the Blackout Report will be implemented. Any actionfall of 2005. If approved, the new rates would go into effect in November 2005.Congress or initiatives by FERC and NERC could significantly impact SCE&G's access to or cost of power for its native load customers and SCE&G's marketing of power outside its service territory.the SCPSC.
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2004MARCH 31, 2005
AS COMPARED TO THE CORRESPONDING PERIODS IN 20032004 Net income for the periods ended September 30, 2004 and 2003 was as follows: Third Quarter Year to Date Millions of dollars 2004 2003 2004 2003 Net income $ 84.4 $ 87.8 $ 195.0 $ 174.8 Third Quarter 2004 vs 2003 First Quarter Millions of dollars 2005 2004 Net income $ 52.1 $ 53.8 primarilyby approximately $4.4 million due to increased operation and maintenance expense of $4.1 million, higher depreciation expense of $4.8and operating expenses related to the Jasper County Electric Generating Station, by $3.3 million lower AFC of $3.7due to milder weather and by $2.6 million and larger tax deductions in 2003 than in 2004 for certain removal costs. This wasdue to other operating expenses. These decreases were partially offset by higherapproximately $8.9 million from increased retail electric marginsrates that went into effect in January 2005. Accelerated depreciation on the Lake Murray back-up dam and recognition of $14.1 million.synthetic fuel tax credits and other items had no effect on net income, as discussed below.Year to Date 2004 vs 2003Recognition of Synthetic Fuel Tax CreditsNetSCE&G holds equity-method investments in two partnerships involved in converting coal to synthetic fuel, the use of which fuel qualifies for federal income increased duetax credits. These synthetic fuel production facilities were placed in operation in 2000 and 2001. Under an accounting plan approved by the SCPSC in June 2000, the synthetic fuel tax credits generated by the partnerships and passed through to higher electric marginsSCE&G, net of $51.4 millionpartnership losses and other expenses, were to be deferred until the SCPSC approved their application to offset capital costs of projects required to comply with legislative or regulatory actions.reductionJanuary 2005 order, the SCPSC approved SCE&G's request to apply these synthetic fuel tax credits to offset the construction costs of preferred dividend requirementsthe Lake Murray Dam project beginning in January 2005. Under the accounting methodology approved by the SCPSC, current and future construction costs related to the project are recorded in utility plant in service in a special dam remediation account outside of $1.7 million, partially offset by lower gas marginsrate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of $3.7 million, higher operation and maintenance expensethe synthetic fuel tax credits. $7.1 million, higher depreciation expense and related tax benefit recognized in the income statement will be equal to the available synthetic fuel tax credits, less partnership losses and other expenses, net of $10.0 million, higher taxes other thantaxes. As a result, the balance of unrecovered costs in the dam remediation account will decline as accelerated depreciation is recorded. Although these entries collectively have no impact on consolidated net income, (primarily property taxes)they can have a significant impact on individual line items within the income statement.$4.7 million and lower AFC of $2.7 million.2005 are as follows:Factors Increasing (Decreasing)
Net Income (millions) Deferred prior
to 2005 Added 1st Quarter 2005 Recognized 1st Quarter 2005 Recognized in Statement of Income: Depreciation and amortization expense — $ (169.7 ) $ (169.7 ) Income tax benefits: From synthetic fuel tax credits $ 134.2 9.8 144.0 From accelerated depreciation — 64.9 64.9 From partnership losses 22.5 1.8 24.3 Total income tax benefits 156.7 76.5 233.2 Losses from Equity Method Investments (58.7 ) (4.8 ) (63.5 ) Impact on Net Income $ — SCE&G'sthe Company's financial statements as follows: Third Quarter Year to Date First Quarter Millions of dollars Millions of dollars Millions of dollars 2004 2003 2004 2003 2005 2004 Income Statement Impact: Income Statement Impact: Income Statement Impact: Reduction in (component of) employee benefit costs $ 0.8 $ 0.7 $ 3.1 $ (0.7 ) Reduction in employee benefit costs $ 1.5 $ 1.4 Other income 3.2 2.2 8.3 6.1 Other income 3.1 2.5 Balance Sheet Impact: Balance Sheet Impact: Balance Sheet Impact: Reduction in (component of) capital expenditures 0.2 0.2 0.9 (0.2 ) Reduction in capital expenditures 0.4 0.4 Component of amount due to (from) Summer Station co-owner 0.1 0.1 0.3 (0.1 ) Component of amount due to Summer Station co-owner 0.1 0.1 Total Pension Income Total Pension Income $ 4.3 $ 3.2 $ 12.6 $ 5.1 Total Pension Income $ 5.1 $ 4.4 SCE&G'sThe Company's portion of SCANA'sin 2004for the first quarter of 2005 increased compared to the corresponding periodsperiod in 20032004 primarily as a result of a more favorable investment market.The decrease in AFC for the quarterthree months ended September 30, 2004 is primarily due to completion of the construction of the Jasper County Electric Generating Station in May 2004. AFC for the nine months ending September 30, 2004March 31, 2005 decreased slightly primarily due to completion of the Jasper County Electric Generating Station in May 2004, offset by2004. Included in the increase inequity portion of AFC resulting fromis approximately $2.8 million, which was accrued as a result of the January 2005 SCPSC rate order related to the back-up dam at Lake Murray Dam Project.Murray.and South Carolina Generating Company, Inc.'s (GENCO) BoardsBoard of Directors havehas declared the following dividends on common stock held by SCANA during 2004:2005:Declaration Date Amount Quarter Ended Payment Date February 19, 200417, 2005 $ 36.038.0 million March 31, 20042005 April 1, 20042005April 29, 2004May 5, 2005 $ 37.038.0 million June 30, 20042005 July 1, 2004July 29, 2004$36.0 millionSeptember 30, 2004October 1, 2004October 29, 2004$36.5 millionDecember 31, 2004January 1, 2005GENCOSouth Carolina Generating Company, Inc. and South Carolina Fuel Company, Inc. Electric operations sales margins were as follows: Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 Operating revenues $ 493.0 14.7 % $ 429.8 $ 1,309.5 16.4 % $ 1,125.0 Less: Fuel used in generation 139.2 43.8 % 96.8 354.7 37.7 % 257.6 Purchased power 10.7 (16.4 )% 12.8 43.1 10.8 % 39.0 Margin $ 343.1 7.1 % $ 320.2 $ 911.7 10.0 % $ 828.4 Third Quarter 2004 vs 2003 Margin increased primarily due to $10.6 million from off-system sales, $10.1 million due to customer growth and consumption, and $2.2 million due to favorable weather.Year to Date 2004 vs 2003Millions of dollars 2005 First Quarter
% Change 2004 Operating revenues $ 416.2 9.2 % $ 381.1 Less: Fuel used in generation 127.7 33.9 % 95.4 Purchased power 6.6 (48.0 )% 12.7 Margin $ 281.9 3.3 % $ 273.0 base rates that went into effect in February 2003,January 2005 for a total impact of $7.1$14.4 million an additional $22.7and customer growth and increase consumption of $1.8 million, which was partially offset by $5.4 million due to favorableunfavorable weather $34.5and by $1.1 million fromrelated to decreased off-system sales and $18.9 million due to customer growth and consumption.sales. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 Operating revenues $ 61.5 12.6 % $ 54.6 $ 275.1 6.4 % $ 258.6 Less: Gas purchased for resale 50.5 15.3 % 43.8 216.6 11.6 % 194.1 Margin $ 11.0 1.9 % $ 10.8 $ 58.5 (9.3 )% $ 64.5 Third Quarter 2004 vs 2003Millions of dollars 2005 First Quarter
% Change 2004 Operating revenues $ 156.9 7.7 % $ 145.7 Less: Gas purchased for resale 120.7 8.9 % 110.8 Margin $ 36.2 3.7 % $ 34.9 growth partially offset by a decreased billing surcharge for the recovery of environmental remediation expenses (offset in operations and maintenance expense).Year to Date 2004 vs 2003 Margin decreased primarily due to a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in operations and maintenance expense) and an unfavorable competitive position of natural gas relative to alternate fuels of $0.4 million.growth. Third Quarter Year to Date Millions of dollars 2004 % Change 2003 2004 % Change 2003 2005 First Quarter
% Change 2004 Other operation and maintenance $ 103.0 7.0 % $ 96.3 $ 315.2 3.8 % $ 303.6 $ 108.5 (0.2 )% $ 108.7 Depreciation and amortization 57.2 15.6 % 49.5 164.6 10.9 % 148.3 233.5 * 51.9 Other taxes 32.2 2.2 % 31.5 101.9 7.9 % 94.4 34.9 (0.3 )% 35.0 Total $ 192.4 8.5 % $ 177.3 $ 581.7 6.5 % $ 546.3 $ 376.9 * $ 195.6 Third Quarter 2004 vs 2003increased primarily due to $3.1 milliondecreased slightly. Increased nuclear and fossil maintenance expenses of increased operating expense at the electric generation plants and $4.6 million were offset by decreases in laborwinter storm expenses of $2.5 million and benefits.employee benefit plan expenses. Depreciation and amortization expense increased $5.0approximately $169.7 million due to accelerated depreciation of the back-up dam at Lake Murray (previously explained atRecognition of Synthetic Fuel Tax Credits) and increased $6.0 million due to the completion of the Jasper County Electric Generating Station in May 2004 and $2.7$3.7 million due to normal net property changes.Year to Date 2004 vs 2003 Other operation and maintenance expenses increased primarily due to increased labor and benefit costs of $6.7 million, 2004 winter storm restoration expenses of $2.5 million, increased expenses at electric generation plants of $5.9 million and other operating expenses of $1.9 million partially offset by a decreased billing surcharge for the recovery of environmental remediation expenses of $4.8 million (offset in gas margin) and increased pension income of $3.8 million. Depreciation and amortization expense increased $8.4 million due to the completion of the Jasper County Electric Generating Station and $7.6 million due to normal net property changes. Other taxes increased primarily due to increased property taxes.AFC. Interest expense year to date increased primarily due to increasedAFC of $2.6 million which was partially offset by lower interest rates and reduced long-term debt.taxestax expense for the quarter increased primarilydecreased by approximately $233.2 million as a resultpreviously described atRecognition of changes in operating incomeSynthetic Fuel Tax Credits, and larger tax deductions in 2003 than in 2004 for certain removal costs. Income taxes year to date increased primarily due to changes in operating income.September 30, 2004March 31, 2005 was 4.37.3.19.SCE&G'sTheitsSCE&G's ability to obtain adequate and timely rate and other regulatory relief.relief, if requested. On October 18, 2004 In a January 2005 order the SCPSC granted SCE&G announced that it had entered into a stipulation and settlement agreement with the Staff of the SCPSC in connection with SCE&G's pending retail electric rate increase application that was filed on July 1, 2004. The settlement agreement is subject to review and approval by the SCPSC. If approved in its entirety, the settlement agreement would result in an overallcomposite increase in retail electric rates of approximately 2.89%, designed to produce additional annual revenues of approximately $51.1$41.4 million (3.57%) based on an adjusteda test year ended March 31, 2004, or about 63% of the $81.2 million (5.66%) overall revenue increase requested in the application.calculation. The settlement agreement establishes an allowedSCPSC lowered SCE&G's return on common equity in a range of 10.4%from 12.45% to an amount not to exceed 11.4%, with rates to be set based on the midpoint of that range (10.9%)at 10.7%. The settlement agreement covers allnew rates became effective in January 2005. As part of its order, the major issues addressed inSCPSC approved SCE&G's application, including recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, recovery of costs of mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Similar settlements have been negotiated with several other intervenorsMurray (as previously discussed in this rate case. Hearings on this request concluded November 5, 2004,Recognition of Synthetic Fuel Tax Credits). The SCPSC also approved recovery over a five-year period of SCE&G's approximately $14 million of costs incurred in the formation of the GridSouth Regional Transmission Organization and recovery through base rates over three years of approximately $25.6 million of purchased power costs that were previously deferred. As a ratepart of its order, is expected by year end. If approved, rates under such an order would go into effect January 1, 2005. There can be no assurance that the SCPSC will approveextended through 2010 its approval of the settlement and stipulation agreement(s), in whole or in part. Further, there can be no assurance as toaccelerated capital recovery plan for SCE&G's Cope Generating Station. Under the level of increase, if any, in retail electric rates arising from these proceedings. Testimony presented in these proceedings covered a range of potential revenue adjustments, from an increase of $81.2 million, as filed by SCE&G, to a reduction of approximately $9 million supported by the Consumer Advocateplan, in the hearing.event that SCE&G would otherwise earn in excess of its maximum allowed return on common equity, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, withoutninethree months ended September 30, 2004March 31, 2005 and 2003:2004: Nine Months Ended
September 30, Three Months Ended
March 31, Millions of dollars 2004 2003 2005 2004 Net cash provided from operating activities $ 339 $ 417 $ 7 $ 96 Net cash provided from (used for) financing activities (85 ) 110 Cash provided from sale of assets 2 — Cash and temporary cash investments available at the beginning of the period 56 23 Net cash provided from financing activities 111 81 Cash and cash equivalents available at the beginning of the period 20 56 Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction $ (281 ) $ (496 ) $ (117 ) $ (150 ) Funds used for nonutility property additions (5 ) — — (1 ) Funds used for investments (14 ) (11 ) (4 ) (3 ) The following describes the revolving credit programs currently utilized by the Company. In June 2004 the Company entered into new five-year revolving committed credit facilities totaling $525 million. These new revolving credit facilities replaced $475 million in existing committed credit facilities. The Company had available the following revolving credit facilities which were unused at September 30, 2004:(Millions) Lines of credit: Committed $ 525 Uncommitted 113 (1) (1)Either SCE&G or SCANA may use this uncommitted line. At September 30, 2004 SCE&G had $165 million in outstanding short-term borrowings at a weighted average interest rate of 1.80%.On February 11, 2004 GENCOIn March 2005 SCE&G issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixedfirst mortgage bonds having an annual interest rate of 5.49%. Proceeds5.25% and maturing March 1, 2035. The proceeds from this issuancethe sale of these bonds were used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose. In May 2004 SCE&G borrowed $23.6 million under an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray Dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million with such borrowings being repaid over ten years from the initial borrowing. At September 30, 2004 SCE&G had $22.1 million outstanding under the agreement. On October 22, 2004 SCE&G borrowed an additional $11.8 million under the agreement. On July 15, 2004 SCE&G retired at maturity $100 millionredemption on April 1, 2005 of first mortgage bonds, bearing interest at 7.70%.7.625% Series due April 1, 2025. In May 2004 SCE&G's 875 megawatt Jasper County Electric Generating Station began commercial operation. The $450 million facility includes three natural gas combustion-turbine generators and one steam-turbine generator. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder is included in the rate case previously discussed.the United States Federal Energy Regulatory Commission (FERC).FERC. Construction for the project and related activities is expected to cost approximately $275 million (excluding AFC) and be completed in the second quarter of 2005. Costs incurred through September 30, 2004March 31, 2005 totaled approximately $223$251 million. See alsoAs discussed below under Other Matters, the previous rate case discussion.Company expects that substantially all of the costs of the Lake Murray Dam project will be covered by synthetic fuel tax credits.Nuclear Station In April 2004 the Nuclear Regulatory Commission (NRC) approved SCE&G's application for a 20-year license extension for its V. C. Summer Nuclear Station (Summer Station). The extension allows the plant to operate through August 6, 2042.two equity-method investments in two partnerships involved in converting coal to non-conventionalsynthetic fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of September 30, 2004 is approximately $3 million, and through September 30, 2004, they have generated and passed through to SCE&G approximately $124 million inThese synthetic fuel tax credits. At September 30, 2004 SCE&G has recorded on its balance sheet $90 million net deferred tax benefits, which includes the effects of partnership losses.aan accounting plan approved by the SCPSC anyin June 2000, the synthetic fuel tax credits generated by the partnerships and ultimately passed through to SCE&G from synfuel produced for and consumed by SCE&G, net of partnership losses and other expenses, have been and willwere to be deferred and will be applieduntil the SCPSC approved their application to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1Bcondensed consolidated financial statements.SCE&G approximately $144.0 million in such tax credits. As discussed previously described at Net Income, in a January 2005 order, the SCPSC approved SCE&G's rate case seeks SCPSC approvalrequest to apply current and anticipated netthese synthetic fuel tax credits to offset the costconstruction costs of constructing the back-upLake Murray Dam project beginning in January 2005. Under the accounting methodology approved by the SCPSC, current and future construction costs related to the project are recorded in utility plant in service in a special dam remediation account outside of rate base, and depreciation will be recognized against the balance in this account on an accelerated basis, subject to the availability of the synthetic fuel tax credits.Lake Murray.the end of 2007.S.C.one of the partnerships, S. C. Coaltech No. l1 L.P. received a "No Change" letter from the Internal Revenue Service (IRS) related to its synthetic fuel operations for the tax year 2000. After review of testing procedures and supporting documentation and conducting an independent investigation, the IRS found that the partnership produces a qualifying fuel under section 29 of the Internal Revenue Code (IRC) and found no reason to challenge the first placed-in-service status of the facility. This letter supports SCANA'sthe Company's position that the synthetic fuel tax credits have been properly claimed. Section 29 of the IRC provides for the reduction of synthetic fuel tax credits for any calendar year in which the average annual wellhead price of oil exceeds an inflation-adjusted base price per barrel (as defined in the IRC, and currently estimated to be approximately $52), up to a maximum price spread (as defined in the IRC, and currently estimated to be in the range of $12-$13), at which point the credits would be completely phased-out. The Company cannot predict what impact, if any, the price of oil may have on the Company's ability to earn synthetic fuel tax credits in the future.
Item 3. Quantitative and Qualitative Disclosures About Market Risk Expected Maturity Date As of March 31, 2005
Millions of dollars
Expected Maturity DateAs of September 30, 2004
Millions of dollars 2004 2005 2006 2007 2008 There-
after Total Fair
ValueLiabilities 2005 2006 2007 2008 2009 There-
after Total Fair
ValueLong-Term Debt: Fixed Rate ($) 3.7 189.2 169.9 39.2 39.2 1,821.9 2,263.1 2,236.7 189.2 169.9 39.2 39.2 139.2 1,818.2 2,394.9 2,285.7 Average Interest Rate (%) 7.78 7.37 8.51 6.86 6.86 6.03 6.36 7.37 8.51 6.86 6.86 6.33 5.98 6.32 n/a
Item 4. Controls and ProceduresSeptember 30, 2004March 31, 2005 an evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that as of September 30, 2004March 31, 2005 the Company's disclosure controls and procedures were effective. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2004March 31, 2005 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
FINANCIAL SECTION
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)Millions of dollars Millions of dollars September 30,
2004 December 31,
2003 Millions of dollars March 31,
2005 December 31,
2004 Assets Assets Assets Gas Utility Plant Gas Utility Plant $ 955 $ 923 Gas Utility Plant $ 958 $ 947 Accumulated Depreciation (272 ) (256 ) Acquisition Adjustment, Net of Accumulated Amortization 210 210 Accumulated depreciation Accumulated depreciation (268 ) (262 ) Acquisition adjustment Acquisition adjustment 210 210 Gas Utility Plant, Net Gas Utility Plant, Net 893 877 Gas Utility Plant, Net 900 895 Nonutility Property and Investments, Net Nonutility Property and Investments, Net 27 28
Nonutility Property and Investments, Net
27
27
Current Assets: Current Assets:
Current Assets:
Cash and temporary investments 2 18 Cash and cash equivalents 18 1 Restricted cash and temporary investments 8 7 Restricted cash and temporary investments — 8 Receivables, net of allowance for uncollectible accounts of $1 and $2 32 115 Receivables, net of allowance for uncollectible accounts of $3 and $2 124 128 Receivables—affiliated companies 2 5 Receivables-affiliated companies 10 7 Inventories (at average cost): Inventories (at average cost): Stored gas 69 56 Stored gas 29 70 Materials and supplies 5 5 Materials and supplies 6 5 Prepayments 10 2 Prepayments 1 2 Deferred income taxes, net 5 3 Deferred income taxes, net 4 4 Other 1 1 Total Current Assets 133 211 Total Current Assets Total Current Assets 193 226 Deferred Debits: Deferred Debits:
Deferred Debits:
Due from affiliate—pension asset 12 13 Due from affiliate-pension asset 12 12 Regulatory assets 23 17 Regulatory assets 10 27 Other 5 6 Other 6 4 Total Deferred Debits 40 36 Total Deferred Debits 28 43 Total Total $ 1,093 $ 1,152 Total $ 1,148 $ 1,191 Capitalization and Liabilities Capitalization: Common equity $ 506 $ 502 Long-term debt, net 274 278 Total Capitalization 780 780 Current Liabilities: Short-term borrowings 19 55 Current portion of long-term debt 8 8 Accounts payable 22 48 Accounts payable—affiliated companies 4 2 Customer deposits 7 7 Taxes accrued 5 10 Interest accrued 3 6 Distributions/dividends declared 3 4 Other 18 15 Total Current Liabilities 89 155 Deferred Credits: Deferred income taxes, net 101 96 Deferred investment tax credits 1 2 Due to affiliate-postretirement benefits 18 17 Other regulatory liabilities 12 9 Non-legal asset retirement obligations 82 77 Other 10 16 Total Deferred Credits 224 217 Commitments and Contingencies (Note 5) — — Total $ 1,093 $ 1,152 Millions of dollars March 31,
2005 December 31,
2004Capitalization and Liabilities Capitalization: Common equity $ 534 $ 513 Long-term debt, net 273 274 Total Capitalization 807 787 Current Liabilities: Short-term borrowings 3 58 Current portion of long-term debt 3 3 Accounts payable 47 66 Accounts payable-affiliated companies 4 8 Customer deposits 9 8 Taxes accrued 18 4 Interest accrued 4 6 Distributions/dividends declared 4 4 Other 6 17 Total Current Liabilities 98 174
Deferred Credits:
Deferred income taxes, net 105 105 Deferred investment tax credits 1 1 Due to affiliate-postretirement benefits 19 19 Other regulatory liabilities 19 10 Asset retirement obligations 86 84 Other 13 11 Total Deferred Credits 243 230 Commitments and Contingencies (Note 5) — — Total $ 1,148 $ 1,191
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONSINCOME
(Unaudited) Three Months Ended
September 30, Nine Months Ended
September 30, Three Months Ended
March 31, Millions of dollars Millions of dollars Millions of dollars 2004 2003 2004 2003 2005 2004 Operating Revenues Operating Revenues $ 53 $ 59 $ 348 $ 344 Operating Revenues $ 246 $ 226 Cost of Gas Cost of Gas 30 37 226 221 Cost of Gas 172 153 Gross Margin Gross Margin 23 22 122 123 Gross Margin 74 73 Operating Expenses: Operating Expenses:
Operating Expenses:
Operation and maintenance 18 19 58 57 Operation and maintenance 20 20 Depreciation 9 9 26 26 Depreciation and amortization 9 9 Other taxes 2 2 6 5 Other taxes 2 2 Total Operating Expenses 29 30 90 88 Total Operating Expenses 31 31 Operating Income (Loss) (6 ) (8 ) 32 35
Operating Income
Operating Income
43
42
Other Income, Including Allowance for Equity Funds Used During Construction Other Income, Including Allowance for Equity Funds Used During Construction 1 2 4 6
Other Income, Including Allowance for Equity Funds Used During Construction
1
—
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction Interest Charges, Net of Allowance for Borrowed Funds Used During Construction 5 5 15 16 Interest Charges, Net of Allowance for Borrowed Funds Used During Construction (5 ) (5 ) Income (Loss) Before Income Tax Expense (Benefit) (10 ) (11 ) 21 25 Income Tax Expense (Benefit) (4 ) (4 ) 8 9
Income Before Income Tax Expense and Earnings from Equity Method Investments
Income Before Income Tax Expense and Earnings from Equity Method Investments
39
37
Income Tax Expense Income Tax Expense 16 14 Net Income (Loss) $ (6 ) $ (7 ) $ 13 $ 16
Income Before Earnings from Equity Method Investments
Income Before Earnings from Equity Method Investments
23
23
Earnings from Equity Method Investments Earnings from Equity Method Investments 1 —
Net Income
Net Income
$
24
$
23
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Nine Months Ended
September 30, Three Months Ended
March 31, Millions of dollars Millions of dollars Millions of dollars 2004 2003 2005 2004 Cash Flows From Operating Activities: Cash Flows From Operating Activities: Cash Flows From Operating Activities: Net income $ 13 $ 16 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 27 28 Net income $ 24 $ 23 Loss on sale of assets 1 — Adjustments to reconcile net income to net cash provided from operating activities: Allowance for funds used during construction (1 ) (1 ) Excess distributions, net of earnings from equity method investments 1 — Changes in certain assets and liabilities: Depreciation and amortization 9 9 (Increase) decrease in receivables, net 86 61 Loss on sale of assets — 1 (Increase) decrease in inventories (13 ) (23 ) Cash provided (used) by changes in certain assets and liabilities: (Increase) decrease in regulatory assets 1 — Receivables, net 1 18 Increase (decrease) in regulatory liabilities 1 — Inventories 40 30 Increase (decrease) in accounts payable (24 ) (20 ) Regulatory liabilities 1 1 Increase (decrease) in deferred income taxes, net 3 5 Accounts payable (22 ) (9 ) Increase (decrease) in taxes accrued (5 ) — Deferred income taxes, net — (1 ) Changes in gas adjustment clauses (6 ) (5 ) Taxes accrued 14 15 Changes in other assets (7 ) (5 ) Changes in gas adjustment clauses 25 7 Changes in other liabilities (1 ) (4 ) Changes in other assets and liabilities (3 ) (6 ) Net Cash Provided From Operating Activities Net Cash Provided From Operating Activities 75 52 Net Cash Provided From Operating Activities 90 88 Cash Flows From Investing Activities: Cash Flows From Investing Activities:
Cash Flows From Investing Activities:
Construction expenditures (39 ) (36 ) Construction expenditures, net of AFC (13 ) (14 ) Nonutility and other (1 ) (1 ) Nonutility and other (1 ) — Net Cash Used For Investing Activities Net Cash Used For Investing Activities (40 ) (37 ) Net Cash Used For Investing Activities (14 ) (14 ) Cash Flows From Financing Activities: Cash Flows From Financing Activities:
Cash Flows From Financing Activities:
Short-term borrowings, net (36 ) 4 Short-term borrowings, net (55 ) (55 ) Capital contribution from parent — 3 Distributions/dividends (4 ) (4 ) Retirement of long-term debt (3 ) (3 ) Distributions/dividend payments (12 ) (15 ) Net Cash Used For Financing Activities Net Cash Used For Financing Activities (51 ) (11 ) Net Cash Used For Financing Activities (59 ) (59 ) Net Increase (Decrease) In Cash and Temporary Investments (16 ) 4 Cash and Temporary Investments, January 1 18 1
Net Increase In Cash and Cash Equivalents
Net Increase In Cash and Cash Equivalents
17
15
Cash and Cash Equivalents, January 1 Cash and Cash Equivalents, January 1 1 18 Cash and Temporary Investments, September 30 $ 2 $ 5 Cash and Cash Equivalents, March 31 Cash and Cash Equivalents, March 31 $ 18 $ 33 Supplemental Cash Flow Information: Supplemental Cash Flow Information: Supplemental Cash Flow Information: Cash paid for—Interest (net of capitalized interest of $1 and $1) $ 16 $ 16 Cash paid for—Interest (net of capitalized interest of $0.1 and $0.2) Cash paid for—Interest (net of capitalized interest of $0.1 and $0.2) $ 7 $ 7 —Income taxes —Income taxes $ 20 14 —Income taxes 2 —
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSSeptember 30, 2004March 31, 2005
(Unaudited)2003.2004. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the year. In the opinion of management, the information furnished herein reflects all adjustments, all of a normal recurring nature, which are necessary for a fair statement of the results for the interim periods reported. "Accounting"Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, as of March 31, 2005 the Company has recorded as of September 30, 2004 approximately $23$10 million and $94$105 million of regulatory assets (including environmental) and liabilities, respectively. Information relating to regulatory assets and liabilities follows.Millions of dollars September 30,
2004 December 31,
2003 March 31,
2005 December 31,
2004 Excess deferred income taxes $ (2 ) — $ (2 ) $ (1 ) Under- (over-) collections—gas cost adjustment clause, net 5 $ (1 ) Under- (over-) collections-gas cost adjustment clause, net (15 ) 10 Deferred environmental remediation costs 8 9 8 8 Non-legal asset retirement obligations (82 ) (77 ) Asset retirement obligations (86 ) (84 ) Total $ (71 ) $ (69 ) $ (95 ) $ (67 ) clean-upcleanup of manufactured gas plant (MGP) sites currently or formerly owned by the Company. A portion of the costs incurred has been recovered through rates. Approximately $1.2 million in costs,Amounts incurred and deferred, net of insurance settlements, have been incurred and deferred for subsequent rate consideration. (See Note 5.)that are not currently being recovered through rates are approximately $1.5 million. Management believes that all MGP cleanupthese costs and the remaining costs of approximately $6.4 million will be recoverable through gas rates.recoverable.Non-legal assetAsset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.$(0.8)$(0.5) million and $(0.9)$(0.7) million as of September 30, 2004March 31, 2005 and December 31, 2003,2004, respectively.2004.2005.20032004 through September 30, 2004March 31, 2005 was as follows:Rate Per Therm Effective Date $ .460.600 January-February 2003January-September 2004.595$.675 March 2003October-November 2004.725April-November 2003.600$.825 December 2003-September 20042004-January 2005$.725 February-March 2005 On October 1, 2004In March 2005 the NCUC approvedCompany refunded approximately $7.7 million in pipeline supplier refunds by a direct bill credit to various customers. This refund resulted in a reduction in restricted cash and the Company's request to increase the benchmark cost of gas from $.600 per therm to $.675 per therm for service rendered on and after October 1, 2004.associated current liability.September 30, 2004 in connection with the Company's 2004 Annual Prudence Review, the NCUC determined that the Company's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2004. For service rendered on and after March 1, 2004,January 21, 2005 the NCUC authorized the Company to implement decrements in its sales and transportationdefer for subsequent rate schedulesconsideration certain expenses incurred to reflect a decreasecomply with the U. S. Department of approximately $5.7 million in the Company's annual fixed gas costs as well as the current over-recoveryTransportation's Pipeline Integrity Management requirements. This accounting treatment was effective November 1, 2004. As of approximately $16.5 million. A state expansion fund, established by the North Carolina General Assembly and funded by refunds from the Company's interstate pipeline transporters, provides financing for expansion into areas that otherwise wouldMarch 31, 2005 such deferrals were not be economically feasible to serve. In June 2000 the NCUC approved the Company's requests for disbursement of up to $28.4 million from the Company's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. The final phase of this project was completed and placed in service in April 2004 at a total cost of approximately $30.2 million.significant. LONG-TERM DEBT In June 2004 the Company entered into a new five-year revolving committed credit facility totaling $125 million which replaced an existing committed credit facility.4. "Accounting"Accounting for Derivative Instruments and Hedging Activities,"as amended, in accounting for derivatives, including those arising from cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk.20032004 Annual Report on Form 10-K.September 30, 2004March 31, 2005 the Company had a deferred net gaincosts of approximately $0.3$2.3 million.September 30, 2004March 31, 2005 the estimated fair value of the Company's swaps totaled $1.8$0.8 million (gain) related to combined notional amounts of $29.9$25.6 million.$6.6$6.4 million, which reflects theits estimated remaining liability at September 30, 2004.March 31, 2005. Amounts incurred and deferred to date, net of insurance settlements, that are not currently being recovered through gas rates are approximately $1.2$1.5 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.
Disclosure of Reportable Segments
(Millions of dollars)Three Months Ended September 30, 2004 2003 External
Revenue Operating
Income (Loss) Segment
Assets External
Revenue Operating
Income (Loss) Segment
AssetsGas Distribution $ 53 $ (6 ) $ 994 $ 59 $ (8 ) $ 997 All Other — n/a 27 — n/a 28 Adjustments/Eliminations — — 72 — — 67 Consolidated Total $ 53 $ (6 ) $ 1,093 $ 59 $ (8 ) $ 1,092
Nine Months Ended September 30,
2004
2003 External
Revenue Operating
Income Segment
Assets External
Revenue Operating
Income Segment
AssetsGas Distribution $ 348 $ 32 $ 994 $ 344 $ 35 $ 997 All Other — n/a 27 — n/a 28 Adjustments/Eliminations — — 72 — — 67 Consolidated Total $ 348 $ 32 $ 1,093 $ 344 $ 35 $ 1,092 Three Months Ended March 31, 2005 2004 External
Revenue Operating
Income
(Loss) Net
Income Segment
Assets External
Revenue Operating
Income
(Loss) Net
Income
(Loss) Segment
AssetsGas Distribution $ 246 $ 43 $ 23 $ 1,055 $ 226 $ 42 $ 23 $ 1,039 All Other — n/a 1 27 — n/a — 28 Adjustments/Eliminations — — — 66 — — — 59 Consolidated Total $ 246 $ 43 $ 24 $ 1,148 $ 226 $ 42 $ 23 $ 1,126
Item 2. Management's Narrative Analysis of Results of Operations.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS2003.2004.ninethree months ended September 30, 2004 decreased $3.2March 31, 2005 increased $1.6 million compared to the same period in 20032004, primarily due to decreased margin of $1.6 million, higher operating expenses of $1.4 million and lower other income of $2.2 million, partially offset by lower income taxes of $1.9 million.increased margin.June 30March 31 and September 30December 31 are generally PSNC Energy's leastmost profitable quarters due to decreasedincreased demand for natural gas related to space heating requirements.2004:2005:Declaration Date Amount Quarter Ended Payment Date February 19, 200417, 2005 $ 4.03.5 million March 31, 20042005 April 1, 20042005April 29, 2004May 5, 2005 $ 3.5 million June 30, 20042005 July 1, 2004July 29, 2004$3.0 millionSeptember 30, 2004October 1, 2004October 29, 2004$3.5 millionDecember 31, 2004January 1, 2005 Nine Months Ended
September 30, Three Months Ended March 31, Millions of dollars Millions of dollars Millions of dollars 2004 Change 2003 2005 Change 2004 Operating revenues Operating revenues $ 347.9 1.1 % $ 344.0 Operating revenues $ 245.9 8.8 % $ 226.0 Less: Gas purchased for resale Less: Gas purchased for resale 226.1 2.5 % 220.6 Less: Gas purchased for resale 172.1 12.2 % 153.4 Margin $ 121.8 (1.3 )% $ 123.4 Margin $ 73.8 1.7 % $ 72.6 ninethree months ended September 30, 2004 decreasedMarch 31, 2005 increased by approximately $2.5 million primarily due to a decline in customer usage per degree-day of approximately $4.0 million,growth and increased consumption, partially offset by customer growth and consumption of approximately $2.3 million.Operation and Maintenance Expenses Operation and maintenance expenses increased $1.4$0.9 million for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to increased labor and benefits costs of $1.9 million and increased administrative and general business expenses of $1.2 million, partially offset by a decrease of $1.7 million in bad debt expense.milder weather.decreased $2.2 million comparedin 2005 improved primarily due to the same period in 2003 primarily due torecognition of a $1.0 million loss recognizedin 2004 on the sale of PSNC Energy's former corporate headquarters in Gastonia, North Carolina and decreased interest income of $0.7 million on amounts under-collected from customers through the operation of the Rider D mechanism. This mechanism allows PSNC Energy to recover all prudently incurred gas costs.headquarters.20042005 construction budget is approximately $51$58 million, compared to actual construction expenditures through September 30, 2004March 31, 2005 of $40.4$11.8 million. PSNC Energy's ratio of earnings to fixed charges for the 12 months ended September 30, 2004March 31, 2005 was 3.13.2.93.In June 2004 PSNC Energy entered into a new five-year revolving committed credit facility totaling $125 million which replaced an existing committed credit facility. At September 30, 2004March 31, 2005 PSNC Energy had $19.1$2.5 million in outstanding short-term borrowings at a weighted average interest rate of 1.87% and2.78%. PSNC Energy also had unused lines of credit of $125 million.million under a five-year revolving credit facility that expires in 2009.
Item 4. Controls and ProceduresSeptember 30, 2004March 31, 2005 an evaluation was performed under the supervision and with the participation of PSNC Energy's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of PSNC Energy's disclosure controls and procedures. Based on that evaluation, PSNC Energy's management, including the CEO and CFO, concluded that as of September 30, 2004March 31, 2005 PSNC Energy's disclosure controls and procedures were effective. There has been no change in PSNC Energy's internal control over financial reporting during the quarter ended September 30, 2004March 31, 2005 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting. On October 18, 2004 South Carolina Electric & Gas Company (SCE&G) announced that it had entered into a stipulation and settlement agreement with the Staff of the Public Service Commission of South Carolina (SCPSC) in connection with SCE&G's pending retail electric rate increase application that was filed on July 1, 2004. The settlement agreement is subject to review and approval by the SCPSC. If approved in its entirety, the settlement agreement would result in an overall increase in retail electric revenues of approximately $51.1 million (3.57%) based on an adjusted test year ended March 31, 2004, or about 63% of the $81.2 million (5.66%) overall revenue increase requested in the application. The settlement agreement establishes an allowed return on common equity in a range of 10.4% to 11.4%, with rates to be set based on the midpoint of that range (10.9%). The settlement agreement covers all of the major issues addressed in SCE&G's application, including recovery of construction and operating costs for SCE&G's new Jasper County Electric Generating Station, mandatory environmental upgrades primarily related to Federal Clean Air Act regulations and the application of current and anticipated net synthetic fuel tax credits to offset the cost of constructing the back-up dam at Lake Murray. Similar settlements have been negotiated with several other intervenors in this rate case. Hearings on this request concluded November 5, 2004, and a rate order is expected by year end. If approved, rates under such an order would go into effect January 1, 2005. There can be no assurance that the SCPSC will approve the settlement and stipulation agreement(s), in whole or in part. Further, there can be no assurance as to the level of increase, if any, in retail electric rates arising from these proceedings. Testimony presented in these proceedings covered a range of potential revenue adjustments, from an increase of $81.2 million, as filed by SCE&G, to a reduction of approximately $9 million supported by the Consumer Advocate in the hearing. In addition, at the November 2004 hearing the SCPSC will consider whether to allow SCE&G to recover through base rates approximately $25.6 million of purchased power costs. These costs were originally approved for recovery through the fuel clause by the SCPSC in a May 2002 order. The Consumer Advocate of South Carolina (Consumer Advocate) appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of these purchased power costs. The Circuit Court ruled that the current fuel clause only provided for the recovery of the fuel costs included in purchased power and not the total cost of the power purchased. The Circuit Court remanded the case to the SCPSC for final disposition. In February 2004 the General Assembly of South Carolina clarified the definition of the fuel clause to include the total cost of power purchased. In April 2004 the SCPSC approved a stipulation agreement between the Consumer Advocate and SCE&G whereby SCE&G would be allowed to defer for recovery in a future rate proceeding the purchased power costs not allowed to be recovered through the fuel clause. SCE&G is seeking recovery of such costs in the current proceedings.SCE&GSouth Carolina Electric & Gas Company (SCE&G) by the State of South Carolina alleging that SCE&G violated the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint alleged that SCE&G failed to obey, observe or comply with the lawful order of the SCPSC by charging franchise fees to those not residing within a municipality. The complaint sought restitution to all affected customers and penalties up to $5,000 for each separate violation. The State of South Carolina v. SCE&G has been settled by an agreement between the parties, and the settlement has been approved by the court. The allegations contained in the complaint were also the subject of a similar lawsuit that was filed and served on SCE&G but has now been dismissed. The allegations are also the subject of a purported class action lawsuit filed on or aboutin December 12, 2003, against Duke Energy Corporation, Progress Energy Services Company and SCE&G (styled as Edwards v. SCE&G). Duke Energy and Progress Energy have, but that case has been voluntarily dismissed fromby the Edwards lawsuit. The Company believes that the resolution ofthese actions will not have a material adverse impact on its results of operations, cash flows or financial condition.Plaintiff. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation that the SCPSC deems just and proper to regulate the franchise fee collection process. The Company believes that the resolution of these matters will not have a material adverse impact on its results of operations, cash flows or financial condition.allegesalleged the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. On October 20, 2004, testimony from all parties was concluded in the Circuit Court and the case was sent to the jury. On October 21, 2004, the jury issued itsan adverse verdict on this matter against SCANA for four causes of action for damages totaling $48 million. Post-verdict motions are scheduledwere heard in November 2004 and January 2005. In April 2005, post-trial motions were decided by the Court, and the plaintiff has been ordered to be heardelect a single remedy from the weekmultiple jury awards.November 15, 2004. It is2004, it was SCANA's interpretation that the damages awarded with respect to certain causes of action are overlapping.were overlapping and that the plaintiff would be required to elect a single remedy. Therefore, it iswas SCANA's belief that a reasonably possible estimate of the total damages based on the amounts awarded by the jury willwould be in the range of $18-$36 million. As such, in accordance with generally accepted accounting principles, in the third quarter of 2004 SCANA accrued a liability of $18 million pre-tax, which was its reasonable estimate of the minimum liability that was probable if the final judgment were to be consistent with the jury verdict.believescontinues to believe that the verdict was inconsistent with the facts presented and applicable law and intends to appeal any adverse judgment ultimately entered by the Circuit Court. Basedcurrent status of this matter, and in accordance with generally accepted accounting principles, SCANA recorded a pre-tax charge to earnings inindemnification was held on January 14, 2005. A ruling has not yet been received, but is expected during the thirdsecond quarter of 2004 of $18 million, $11 million after-tax, or 10 cents per share, which is SCANA's reasonable estimate of the loss that is probable if the final judgment is consistent with the jury verdict. In addition to other environmental costs being recovered through billing surcharges, as of September 30, 2004, SCE&G is party to certain claims for costs and damages arising from the prior operation of a manufactured gas plant in the Calhoun Park area of Charleston, South Carolina, for which claims the National Park Service of the Department of the Interior has demanded payment of approximately $9 million. Any cost arising from the ultimate settlement of these matters is also expected to be recoverable through rates under South Carolina regulatory processes.2005.PSNC EnergyPublic Service Company of North Carolina, Incorporated (PSNC Energy) are engaged in various claims and litigation incidental to their business operations which for 2003 have not changed significantly unless noted above.
Item 6. Exhibits and Reports on Form 8-KA. ExhibitsIncorporated:Incorporated (PSNC Energy): Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit numbers in prior filings are hereby incorporated herein by reference and made a part hereof.B. Reports on Form 8-K during the third quarter 2004 were as follows:SCANA Corporation:Date of report: July 23, 2004Items reported: Items 7 & 12South Carolina Electric & Gas Company:Date of report: July 23, 2004Items reported: Items 7 & 12Public Service Company of North Carolina, Incorporated:Date of report: July 23, 2004Items reported: Items 7 & 12 SCANA CORPORATION
SOUTH CAROLINA ELECTRIC & GAS COMPANY
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
(Registrants)November 9, 2004May 6, 2005
By:
/s/ JAMES E. SWAN, IV
James E. Swan, IV
Controller
(Principal accounting officer) Applicable to Form 10-Q ofApplicable to Form 10-Q of Exhibit
No. SCANA SCE&G PSNC
Energy Description 3.013.11 X Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein)3.02X
Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein)3.03X
March 9, 2005 amending the Restated Articles of Incorporation of South Carolina Electric & Gas Company as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-65460 and incorporated by reference herein)3.04XArticles of Amendment effective as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference hereinMay 22, 2001Exhibit 3.02to Registration No. 333-65460June 14, 2001Exhibit 3.04to Registration No. 333-65460August 30, 2001Exhibit 3.05to Registration No. 333-101449March 13, 2002Exhibit 3.06to Registration No. 333-101449May 9, 2002Exhibit 3.07to Registration No. 333-101449June 4, 2002Exhibit 3.08to Registration No. 333-101449August 12, 2002Exhibit 3.09to Registration No. 333-101449March 13, 2003Exhibit 3.03to Registration No. 333-108760May 22, 2003Exhibit 3.04to Registration No. 333-108760June 18, 2003Exhibit 3.05to Registration No. 333-108760August 7, 2003Exhibit 3.06to Registration No. 333-108760May 18, 2004Exhibit 3.05to Form 10-Q for the quarter ended June 30, 2004June 18, 2004Exhibit 3.06to Form 10-Q for the quarter ended June 30, 20043.05XArticles of Amendment dated August 12, 2004 (Filed herewith)3.06XArticles of Correction filed on June 1, 2001 correcting May 22, 2001 Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No. 333-65460 and incorporated by reference herein)3.07XArticles of Correction filed on February 17, 2004 correcting the Articles of Amendment dated as indicated below and filed as exhibits to Form 10-K for the year ended December 31, 2003 and are incorporated by reference hereinMay 3, 2001Exhibit 3.06May 22, 2001Exhibit 3.07June 14, 2001Exhibit 3.08August 30, 2001Exhibit 3.09March 13, 2002Exhibit 3.10May 9, 2002Exhibit 3.11June 4, 2002Exhibit 3.12August 12, 2002Exhibit 3.13March 13, 2003Exhibit 3.14May 22, 2003Exhibit 3.15June 18, 2003Exhibit 3.16August 7, 2003Exhibit 3.173.08XBy-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. 333-68266 and incorporated by reference herein)3.09XBy-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein)3.10XBy-Laws of PSNC Energy as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. 333-68516 and incorporated by reference herein)4.01XXArticles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein)4.02XIndenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein)4.03XXIndenture dated as of January 1, 1945, between the South Carolina Power Company and Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Filed as Exhibit 2-B to Registration Statement No. 2-26459 and incorporated by reference herein)4.04XXFourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture (Exhibit 2-C to Registration Statement No. 2-26459 and incorporated by reference herein)4.05XXFifth through Fifty-third Supplemental Indenture referred to in Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the Registration Statements set forth below and are incorporated by reference hereinDecember 1, 1950Exhibit 2-Dto Registration No. 2-26459July 1, 1951Exhibit 2-Eto Registration No. 2-26459June 1, 1953Exhibit 2-Fto Registration No. 2-26459June 1, 1955Exhibit 2-Gto Registration No. 2-26459November 1, 1957Exhibit 2-Hto Registration No. 2-26459September 1, 1958Exhibit 2-Ito Registration No. 2-26459September 1, 1960Exhibit 2-Jto Registration No. 2-26459June 1, 1961Exhibit 2-Kto Registration No. 2-26459December 1, 1965Exhibit 2-Lto Registration No. 2-26459June 1, 1966Exhibit 2-Mto Registration No. 2-26459June 1, 1967Exhibit 2-Nto Registration No. 2-29693September 1, 1968Exhibit 4-Oto Registration No. 2-31569June 1, 1969Exhibit 4-Cto Registration No. 33-38580December 1, 1969Exhibit 4-Oto Registration No. 2-35388June 1, 1970Exhibit 4-Rto Registration No. 2-37363March 1, 1971Exhibit 2-B-17to Registration No. 2-40324January 1, 1972Exhibit 2-Bto Registration No. 33-38580July 1, 1974Exhibit 2-A-19to Registration No. 2-51291May 1, 1975Exhibit 4-Cto Registration No. 33-38580July 1, 1975Exhibit 2-B-21to Registration No. 2-53908February 1, 1976Exhibit 2-B-22to Registration No. 2-55304December 1, 1976Exhibit 2-B-23to Registration No. 2-57936March 1, 1977Exhibit 2-B-24to Registration No. 2-58662May 1, 1977Exhibit 4-Cto Registration No. 33-38580February 1, 1978Exhibit 4-Cto Registration No. 33-38580June 1, 1978Exhibit 2-A-3to Registration No. 2-61653April 1, 1979Exhibit 4-Cto Registration No. 33-38580June 1, 1979Exhibit 2-A-3to Registration No. 33-38580April 1, 1980Exhibit 4-Cto Registration No. 33-38580June 1, 1980Exhibit 4-Cto Registration No. 33-38580December 1, 1980Exhibit 4-Cto Registration No. 33-38580April 1, 1981Exhibit 4-Dto Registration No. 33-38580June 1, 1981Exhibit 4-Dto Registration No. 33-49421March 1, 1982Exhibit 4-Dto Registration No. 2-73321April 15, 1982Exhibit 4-Dto Registration No. 33-49421May 1, 1982Exhibit 4-Dto Registration No. 33-49421December 1, 1984Exhibit 4-Dto Registration No. 33-49421December 1, 1985Exhibit 4-Dto Registration No. 33-49421June 1, 1986Exhibit 4-Dto Registration No. 33-49421February 1, 1987Exhibit 4-Dto Registration No. 33-49421September 1, 1987Exhibit 4-Dto Registration No. 33-49421January 1, 1989Exhibit 4-Dto Registration No. 33-49421January 1, 1991Exhibit 4-Dto Registration No. 33-49421July 15, 1991Exhibit 4-Dto Registration No. 33-49421August 15, 1991Exhibit 4-Dto Registration No. 33-49421April 1, 1993Exhibit 4-Eto Registration No. 33-49421July 1, 1993Exhibit 4-Dto Registration No. 33-49421May 1, 1999Exhibit 4.04to Registration No. 333-863874.06XXIndenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)4.07XXFirst Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)4.08XXSecond Supplemental Indenture to Indenture referred to in Exhibit 4.06 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)4.09XXIndenture dated as of January 1, 1996 between PSNC and First Union National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to Registration Statement No. 333-45206 and incorporated by reference herein)4.10XXFirst through Fourth Supplemental Indenture referred to in Exhibit 4.09 dated as of the dates indicated below and filed as exhibits to the Registration Statements whose file numbers are set forth below and are incorporated by reference hereinJanuary 1, 1996Exhibit 4.09to Registration No. 333-45206December 15, 1996Exhibit 4.10to Registration No. 333-45206February 10, 2000Exhibit 4.11to Registration No. 333-45206February 12, 2001Exhibit 4.05to Registration No. 333-685164.11XXPSNC $150 million medium-term note issued February 16, 2001 (Filed as Exhibit 4.06 to Registration Statement No. 333-68516 and incorporated by reference herein)*10.01XXXSCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and incorporated by reference herein)*10.02XXXSCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by reference herein)*10.03XXXAmendment to SCANA Director Compensation and Deferral Plan adopted April 29, 2004 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)*10.04XXXSCANA Supplementary Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)*10.05XXXSCANA Key Executive Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)*10.06XXXSCANA Supplementary Key Severance Benefits Plan as amended July 1, 2001 (Filed as Exhibit 10.03a to Form 10-Q for the quarter ended September 30, 2001 and incorporated by reference herein)*10.07XXXSCANA Long-Term Equity Compensation Plan dated January 2000 (Filed as Exhibit 4.04 to Registration Statement No. 333-37398 and incorporated by reference herein)*10.08XXXAmendment to SCANA Long-Term Equity Compensation Plan adopted April 29, 2004 (Filed as Exhibit 10.08 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)*10.09XXXDescription of SCANA Whole Life Option (Filed as Exhibit 10-F to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809 and incorporated by reference herein)*10.10XXXDescription of SCANA Corporation Executive Annual Incentive Plan (Filed as Exhibit 10-G to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809 and incorporated by reference herein)10.11XOperating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. 333-45206 and incorporated by reference herein)10.12XAmendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206 and incorporated by reference herein)10.13XAmended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. 333-45206 and incorporated by reference herein)10.14XAmended Construction, Operation and Maintenance Agreement by and between Cardinal Operating Company and Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.04 to Registration Statement No. 333-45206 and incorporated by reference herein)10.15XService Agreement between PSNC and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 10.15 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)10.16XService Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 (Filed as Exhibit 10.16 to Form 10-Q for the quarter ended March 31, 2004 and incorporated by reference herein)
31.01
X
Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.02
X
Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.03
X
Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.04
X
Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
31.05
X
Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith)
31.06
X
Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith)
32.01
X
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)
32.02
X
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)31.0332.03
X
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)31.0432.04
X
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)31.0532.05
X
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)31.0632.06
X
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith)*Management Contract or Compensatory Plan or Arrangement
INDEX
SCANA CORPORATION FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
SCANA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
SCANA CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS March 31, 2005 (Unaudited)
SCANA CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2005 AS COMPARED TO THE CORRESPONDING PERIOD IN 2004
SOUTH CAROLINA ELECTRIC & GAS COMPANY FINANCIAL SECTION
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
SOUTH CAROLINA ELECTRIC & GAS COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS March 31, 2005 (Unaudited)
Disclosure of Reportable Segments (Millions of Dollars)Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
SOUTH CAROLINA ELECTRIC & GAS COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL Item 3. Quantitative and Qualitative Disclosures About Market RiskItem 4. Controls and ProceduresSECTION
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED FINANCIAL SECTIONItem 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsCONDITION AND RESULTS OF OPERATIONSItem 3. Quantitative and Qualitative Disclosures About Market RiskRESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2005 AS COMPARED TO THE CORRESPONDING PERIODS IN 2004Item 4. Controls and Procedures
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)Item 2. Management's Narrative Analysis of Results of Operations.PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)Item 4. Controls and ProceduresPUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS March 31, 2005 (Unaudited)
Disclosure of Reportable Segments (Millions of dollars)
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
PART II. OTHER INFORMATION
SIGNATURES
EXHIBIT INDEX