QuickLinks-- Click here to rapidly navigate through this documentUNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,DCD.C. 20549FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from to Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. 1-8809 SCANA Corporation 57-0784499 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-3375 South Carolina Electric & Gas Company 57-0248695 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201 (803) 217-9000 1-11429 Public Service Company of North Carolina, Incorporated 56-2128483 (a South Carolina Corporation) 1426 Main Street, Columbia, South Carolina 29201
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2004 | |
or | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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 Xý Noo South Carolina Electric & Gas Company Yes Xý Noo Public Service Company of North Carolina, Incorporated Yes Xý Noo.
Indicate by check mark whether the registrant is an accelerated filer (
as(as defined in Exchange Act Rule 12b-2). SCANA Corporation Yes Xý Noo South Carolina Electric & Gas Company Yeso No Xý Public Service Company of North Carolina, Incorporated Yeso No Xý.
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Description of Shares Outstanding
Registrant Common Stock at October 31,
---------- ------------ --------------
2003
SCANA Corporation Without Par Value 110,748,408
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)
Registrant | Description of Common Stock | Shares Outstanding at April 30, 2004 | |||
---|---|---|---|---|---|
SCANA Corporation | Without Par Value | 111,114,644 | |||
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)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).
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Page | ||||
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PART I. FINANCIAL INFORMATION | ||||
SCANA Corporation Financial | 3 | |||
Item 1. | Financial Statements | |||
Condensed Consolidated Balance Sheets as of | 4 | |||
Condensed Consolidated Statements of | 6 | |||
Condensed Consolidated Statements of Cash Flows for the Periods Ended | 7 | |||
Condensed Consolidated Statements of Comprehensive Income | 8 | |||
Notes to Condensed Consolidated Financial | 9 | |||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of | 19 | ||
Item 3. | Quantitative and Qualitative Disclosures About Market | 26 | ||
Item 4. | Controls and | 27 | ||
South Carolina Electric & Gas Company Financial | 28 | |||
Item 1. | Financial Statements | |||
Condensed Consolidated Balance Sheets as of | 29 | |||
Condensed Consolidated Statements of Income for the Periods Ended | 31 | |||
Condensed Consolidated Statements of Cash Flows for the Periods Ended | 32 | |||
Notes to Condensed Consolidated Financial | 33 | |||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of | 40 | ||
Item 3. | Quantitative and Qualitative Disclosures About Market | 46 | ||
Item 4. | Controls and | 46 | ||
Public Service Company of North Carolina, Incorporated Financial | 47 | |||
Item 1. | Financial Statements | |||
Condensed Consolidated Balance Sheets as of | 48 | |||
Condensed Consolidated Statements of | 49 | |||
Condensed Consolidated Statements of Cash Flows for the Periods Ended | 50 | |||
Notes to Condensed Consolidated Financial | 51 | |||
Item 2. | Management's Narrative Analysis of Results of | 54 | ||
Item 4. | Controls and | 55 | ||
PART II. OTHER INFORMATION | ||||
Item 1. | Legal | 56 | ||
Item 2. | Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities | 56 | ||
Item 6. | Exhibits and Reports on Form | 56 | ||
Signatures | 58 | |||
Exhibit | 59 |
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ------------------------------------------------------------------------------- ------------------ ------------------
September 30, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------- ------------------ ------------------
Assets
Utility Plant:
Electric $5,416 $5,228
Gas 1,650 1,593
Other 181 184
- ------------------------------------------------------------------------------- ------------------ ------------------
Total 7,247 7,005
Accumulated depreciation and amortization (2,606) (2,476)
- ------------------------------------------------------------------------------- ------------------ ------------------
Total 4,641 4,529
Construction work in progress 994 677
Nuclear fuel, net of accumulated amortization 41 38
Acquisition adjustments, net of accumulated amortization 230 230
- ------------------------------------------------------------------------------- ------------------ ------------------
Utility Plant, Net 5,906 5,474
- ------------------------------------------------------------------------------- ------------------ ------------------
Nonutility Property, Net of Accumulated Depreciation 93 95
Investments 222 231
- ------------------------------------------------------------------------------- ------------------ ------------------
- ------------------------------------------------------------------------------- ------------------ ------------------
Nonutility Property and Investments, Net 315 326
- ------------------------------------------------------------------------------- ------------------ ------------------
- ------------------------------------------------------------------------------- ------------------ ------------------
Current Assets:
Cash and temporary investments 80 374
Receivables, net of allowance for uncollectible accounts of
$15 and $17 358 478
Receivables - affiliated companies 15 8
Inventories (at average cost):
Fuel 169 166
Materials and supplies 60 61
Emission allowances 7 10
Prepayments 36 40
Deferred income taxes, net 4 -
- ------------------------------------------------------------------------------- ------------------ ------------------
Total Current Assets 729 1,137
- ------------------------------------------------------------------------------- ------------------ ------------------
Deferred Debits:
Environmental 21 27
Nuclear plant decommissioning - 87
Assets held in trust, net-nuclear decommissioning 35 -
Pension asset, net 269 265
Other regulatory assets 331 292
Other 182 138
- ------------------------------------------------------------------------------- ------------------ ------------------
Total Deferred Debits 838 809
- ------------------------------------------------------------------------------- ------------------ ------------------
Total $7,788 $7,746
=============================================================================== ================== ==================
- ------------------------------------------------------------------------------------ ------------------- -----------------
September 30, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------------ ------------------- -----------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,306 $2,177
Preferred stock (Not subject to purchase or sinking funds) 106 106
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Stockholders' Investment 2,412 2,283
Preferred Stock, net (Subject to purchase or sinking funds) 9 9
SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55%
Junior Subordinated Debentures of SCE&G - 50
Long-Term Debt, net 2,852 2,834
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Capitalization 5,273 5,176
- ------------------------------------------------------------------------------------ ------------------- -----------------
Current Liabilities:
Short-term borrowings 242 209
Current portion of long-term debt 402 413
Accounts payable 201 354
Accounts payable - affiliated companies 14 8
Customer deposits 43 39
Taxes accrued 72 78
Interest accrued 52 52
Dividends declared 41 39
Deferred income taxes, net - 4
Other 51 77
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Current Liabilities 1,118 1,273
- ------------------------------------------------------------------------------------ ------------------- -----------------
Deferred Credits:
Deferred income taxes, net 782 747
Deferred investment tax credits 119 118
Reserve for nuclear plant decommissioning - 87
Asset retirement obligation - nuclear plant 116 -
Postretirement benefits 133 131
Regulatory liabilities 144 114
Other 103 100
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Deferred Credits 1,397 1,297
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total $7,788 $7,746
==================================================================================== =================== =================
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- -------------------------------------------------------------------- --------------------------- ---------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars, except per share amounts 2003 2002 2003 2002
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Operating Revenues:
Electric $429 $424 $1,121 $1,075
Gas - regulated 155 136 775 587
Gas - nonregulated 167 134 650 503
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Total Operating Revenues 751 694 2,546 2,165
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Operating Expenses:
Fuel used in electric generation 97 105 258 271
Purchased power 13 7 39 29
Gas purchased for resale 262 215 1,127 828
Other operation and maintenance 135 126 420 383
Depreciation and amortization 60 55 180 163
Other taxes 34 32 104 95
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Total Operating Expenses 601 540 2,128 1,769
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Operating Income 150 154 418 396
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Other Income:
Other income, including allowance for equity funds
used during construction of $6, $6, $15 and $18 16 17 48 54
Gain on sale of investments and assets 3 - 60 31
Impairment of investments - - (7) (255)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Total Other Income (Expense) 19 17 101 (170)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income Before Interest Charges, Income Taxes,
Preferred Stock Dividends and Cumulative Effect
of Accounting Change 169 171 519 226
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction of $3, $3, $9 and $10 48 49 149 151
Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities - 1 2 3
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 121 121 368 72
Income Tax Expense 35 41 120 20
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income Before Preferred Stock Dividends and
Cumulative Effect of Accounting Change 86 80 248 52
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 2 2 6 6
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income Before Cumulative Effect of Accounting Change 84 78 242 46
Cumulative Effect of Accounting Change, net of taxes - - - (230)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Net Income (Loss) $84 $78 $242 $(184)
==================================================================== =============== =========== ============ ==============
==================================================================== =============== =========== ============ ==============
Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $.76 $.74 $2.18 $.44
Cumulative Effect of Accounting Change, net of taxes - - - (2.20)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Basic and Diluted Earnings (Loss) Per Share $.76 $.74 $2.18 $(1.76)
==================================================================== =============== =========== ============ ==============
==================================================================== =============== =========== ============ ==============
Weighted Average Shares Outstanding (millions) 110.9 104.7 110.9 104.7
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------------- ----------------------------------
Nine Months Ended
September 30,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash Flows From Operating Activities:
Net income (loss) $242 $(184)
Adjustments to reconcile net income (loss) to net cash provided from operating
activities:
Cumulative effect of accounting change, net of taxes - 230
Depreciation and amortization 188 172
Amortization of nuclear fuel 18 14
Gain on sale of investments and assets (60) (31)
Hedging activities (4) 45
Investment impairments 7 255
Allowance for funds used during construction (24) (28)
Over (under) collection, fuel adjustment clauses 18 (39)
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 113 82
(Increase) decrease in inventories 1 (10)
(Increase) decrease in prepayments 4 (1)
(Increase) decrease in pension asset (4) (20)
(Increase) decrease in other regulatory assets (20) -
Increase (decrease) in deferred income taxes, net 27 (138)
Increase (decrease) in regulatory liabilities 38 32
Increase (decrease) in postretirement benefits obligations 2 7
Increase (decrease) in accounts payable (147) (62)
Increase (decrease) in taxes accrued (6) (18)
Increase (decrease) in interest accrued - 9
Changes in other assets (5) 12
Changes in other liabilities 11 20
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Cash Provided From Operating Activities 399 347
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (558) (424)
Proceeds from sale of investments and assets 69 335
Increase in nonutility property (6) (12)
Investments in affiliates (11) (25)
- --------------------------------------------------------------------------------------- ------------------ ---------------
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Cash Used For Investing Activities (506) (126)
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 495 295
Issuance of Pollution Control Bonds 36 -
Issuance of notes and loans - 497
Issuance of common stock upon exercise of stock options 4 -
Repayments:
Mortgage bonds (250) (104)
Notes and loans (271) (907)
Pollution Control Bonds (43) -
Retirement of preferred stock - (1)
SCE&G Trust I Preferred Securities (50) -
Payment of deferred financing costs (22) -
Dividends and distributions:
Common stock (113) (100)
Preferred stock (6) (6)
Short-term borrowings, net 33 84
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Cash Used For Financing Activities (187) (242)
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Decrease In Cash and Temporary Investments (294) (21)
Cash and Temporary Investments, January 1 374
192
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash and Temporary Investments, September 30 $80 $171
======================================================================================= ================== ===============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $9 and $10) $149 $142
- Income taxes 63 131
Noncash Investing and Financing Activities:
Unrealized gain on securities available for sale, net of tax 1 17
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- ----------------------------------------------------------------------- ----------------------- -----------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars 2003 2002 2003 2002
- ----------------------------------------------------------------------- ----------- ----------- ---------- ------------
- ----------------------------------------------------------------------- ----------- ----------- ---------- ------------
Net Income (Loss) $84 $78 $242 $(184)
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on securities available for sale 1 (12) 1 17
Unrealized gains (losses) on hedging activities (2) 1 (4) 28
- ----------------------------------------------------------------------- ----------- ----------- ---------- ------------
Total Comprehensive Income (Loss) (1) $83 $67 $239 $(139)
======================================================================= =========== =========== ========== ============
(1) Accumulated other comprehensive income (loss) of the Company totaled $(1.1)
million and $1.0 million as of September 30, 2003 and December 31, 2002,
respectively.
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||||
---|---|---|---|---|---|---|---|---|---|
Assets | |||||||||
Utility Plant: | |||||||||
Electric | $ | 5,616 | $ | 5,558 | |||||
Gas | 1,691 | 1,687 | |||||||
Common | 196 | 193 | |||||||
Total | 7,503 | 7,438 | |||||||
Accumulated depreciation and amortization | (2,316 | ) | (2,280 | ) | |||||
Total | 5,187 | 5,158 | |||||||
Construction work in progress | 1,035 | 987 | |||||||
Nuclear fuel, net of accumulated amortization | 36 | 42 | |||||||
Acquisition adjustments, net of accumulated amortization | 230 | 230 | |||||||
Utility Plant, Net | 6,488 | 6,417 | |||||||
Nonutility Property, Net of Accumulated Depreciation | 93 | 96 | |||||||
Investments | 168 | 178 | |||||||
Nonutility Property and Investments, Net | 261 | 274 | |||||||
Current Assets: | |||||||||
Cash and temporary investments | 218 | 117 | |||||||
Receivables, net of allowance for uncollectible accounts of $23 and $16 | 494 | 503 | |||||||
Receivables—affiliated companies | 18 | 13 | |||||||
Inventories (at average cost): | |||||||||
Fuel | 94 | 147 | |||||||
Materials and supplies | 62 | 60 | |||||||
Emission allowances | 13 | 6 | |||||||
Prepayments | 41 | 36 | |||||||
Deferred income taxes, net | 12 | — | |||||||
Total Current Assets | 952 | 882 | |||||||
Deferred Debits: | |||||||||
Environmental | 19 | 20 | |||||||
Assets held in trust, net—nuclear decommissioning | 46 | 44 | |||||||
Pension asset, net | 274 | 270 | |||||||
Other regulatory assets | 328 | 348 | |||||||
Other | 181 | 175 | |||||||
Total Deferred Debits | 848 | 857 | |||||||
Total | $ | 8,549 | $ | 8,430 | |||||
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||
---|---|---|---|---|---|---|---|
Capitalization and Liabilities | |||||||
Shareholders' Investment: | |||||||
Common equity | $ | 2,370 | $ | 2,306 | |||
Preferred stock (Not subject to purchase or sinking funds) | 106 | 106 | |||||
Total Shareholders' Investment | 2,476 | 2,412 | |||||
Preferred Stock, net (Subject to purchase or sinking funds) | 9 | 9 | |||||
Long-Term Debt, net | 3,332 | 3,225 | |||||
Total Capitalization | 5,817 | 5,646 | |||||
Current Liabilities: | |||||||
Short-term borrowings | 191 | 195 | |||||
Current portion of long-term debt | 202 | 202 | |||||
Accounts payable | 238 | 288 | |||||
Accounts payable—affiliated companies | 16 | 12 | |||||
Customer deposits | 45 | 43 | |||||
Taxes accrued | 51 | 81 | |||||
Interest accrued | 57 | 55 | |||||
Dividends declared | 43 | 41 | |||||
Deferred income taxes, net | — | 4 | |||||
Other | 49 | 74 | |||||
Total Current Liabilities | 892 | 995 | |||||
Deferred Credits: | |||||||
Deferred income taxes, net | 802 | 790 | |||||
Deferred investment tax credits | 116 | 117 | |||||
Asset retirement obligation—nuclear plant | 119 | 118 | |||||
Postretirement benefits | 136 | 135 | |||||
Other regulatory liabilities | 549 | 519 | |||||
Other | 118 | 110 | |||||
Total Deferred Credits | 1,840 | 1,789 | |||||
Commitments and Contingencies | — | — | |||||
Total | $ | 8,549 | $ | 8,430 | |||
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
| Three Months Ended March 31, | ||||||
---|---|---|---|---|---|---|---|
Millions of dollars, except per share amounts | |||||||
2004 | 2003 | ||||||
Operating Revenues: | |||||||
Electric | $ | 380 | $ | 336 | |||
Gas—regulated | 426 | 427 | |||||
Gas—nonregulated | 330 | 306 | |||||
Total Operating Revenues | 1,136 | 1,069 | |||||
Operating Expenses: | |||||||
Fuel used in electric generation | 95 | 81 | |||||
Purchased power | 13 | 10 | |||||
Gas purchased for resale | 577 | 571 | |||||
Other operation and maintenance | 155 | 144 | |||||
Depreciation and amortization | 63 | 60 | |||||
Other taxes | 39 | 35 | |||||
Total Operating Expenses | 942 | 901 | |||||
Operating Income | 194 | 168 | |||||
Other Income, Including Allowance for Equity Funds Used During Construction of $6 and $5 | 14 | 16 | |||||
Income Before Interest Charges, Income Taxes and Preferred Stock Dividends | 208 | 184 | |||||
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $4 and $2 | 50 | 51 | |||||
Dividend Requirement of SCE&G—Obligated Mandatorily Redeemable Preferred Securities | — | 1 | |||||
Income Before Income Taxes and Preferred Stock Dividends | 158 | 132 | |||||
Income Tax Expense | 55 | 46 | |||||
Income Before Preferred Stock Dividends | 103 | 86 | |||||
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) | 2 | 2 | |||||
Net Income | $ | 101 | $ | 84 | |||
Basic and Diluted Earnings Per Share of Common Stock | $ | .91 | $ | .75 | |||
Weighted Average Shares Outstanding (millions) | 110.9 | 110.8 |
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| Three Months Ended March 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||||
2004 | 2003 | |||||||||
Cash Flows From Operating Activities: | ||||||||||
Net income | $ | 101 | $ | 84 | ||||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||||
Depreciation and amortization | 64 | 62 | ||||||||
Amortization of nuclear fuel | 6 | 6 | ||||||||
Loss on sale of assets | 1 | — | ||||||||
Hedging activities | (3 | ) | (3 | ) | ||||||
Allowance for funds used during construction | (10 | ) | (7 | ) | ||||||
Over collection, fuel adjustment clauses | 42 | 16 | ||||||||
Changes in certain assets and liabilities: | ||||||||||
(Increase) decrease in receivables, net | 4 | (38 | ) | |||||||
(Increase) decrease in inventories | 44 | 62 | ||||||||
(Increase) decrease in prepayments | (5 | ) | — | |||||||
(Increase) decrease in pension asset | (4 | ) | (1 | ) | ||||||
(Increase) decrease in other regulatory assets | 1 | (1 | ) | |||||||
Increase (decrease) in deferred income taxes, net | 1 | 1 | ||||||||
Increase (decrease) in regulatory liabilities | 3 | 9 | ||||||||
Increase (decrease) in postretirement benefits obligations | 1 | 3 | ||||||||
Increase (decrease) in accounts payable | (46 | ) | 10 | |||||||
Increase (decrease) in taxes accrued | (30 | ) | (24 | ) | ||||||
Increase (decrease) in interest accrued | 2 | 6 | ||||||||
Changes in other assets | 4 | (10 | ) | |||||||
�� | Changes in other liabilities | (13 | ) | (20 | ) | |||||
Net Cash Provided From Operating Activities | 163 | 155 | ||||||||
Cash Flows From Investing Activities: | ||||||||||
Utility property additions and construction expenditures, net of AFC | (122 | ) | (171 | ) | ||||||
Increase in nonutility property | (4 | ) | (3 | ) | ||||||
Investments in affiliates | (3 | ) | (4 | ) | ||||||
Net Cash Used For Investing Activities | (129 | ) | (178 | ) | ||||||
Cash Flows From Financing Activities: | ||||||||||
Proceeds: | ||||||||||
Issuance of First Mortgage Bonds | — | 198 | ||||||||
Issuance of notes and loans | 100 | — | ||||||||
Issuance of common stock upon exercise of stock options | 15 | — | ||||||||
Repayments: | ||||||||||
Notes and loans | — | (60 | ) | |||||||
Repurchase of common stock | (4 | ) | — | |||||||
Dividends and distributions: | ||||||||||
Common stock | (38 | ) | (37 | ) | ||||||
Preferred stock | (2 | ) | (2 | ) | ||||||
Short-term borrowings, net | (4 | ) | (95 | ) | ||||||
Net Cash Provided From Financing Activities | 67 | 4 | ||||||||
Net Increase (Decrease) In Cash and Temporary Investments | 101 | (19 | ) | |||||||
Cash and Temporary Investments, January 1 | 117 | 341 | ||||||||
Cash and Temporary Investments, March 31 | $ | 218 | $ | 322 | ||||||
Supplemental Cash Flow Information: | ||||||||||
Cash paid for—Interest (net of capitalized interest of $4 and $2) | $ | 47 | $ | 46 | ||||||
—Income taxes | — | 1 | ||||||||
Noncash Investing and Financing Activities: | ||||||||||
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 March 31, | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||
2004 | 2003 | |||||||
Net Income | $ | 101 | $ | 84 | ||||
Other Comprehensive Income (Loss), net of tax: | ||||||||
Unrealized losses on securities available for sale | (6 | ) | — | |||||
Unrealized losses on hedging activities | (2 | ) | (2 | ) | ||||
Total Comprehensive Income(1) | $ | 93 | $ | 82 | ||||
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2003
March 31, 2004
(Unaudited)
The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in SCANA Corporation's (the(together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2002.2003. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of OperationsIncome 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
A. Basis of Accounting
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 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, the Company has recorded as of September 30, 2003,March 31, 2004, approximately $352$347 million and $144$549 million of regulatory assets (including environmental) and liabilities, respectively, as shown below.
September 30, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Accumulated deferred income taxes, net $95 $95
Under-collections - electric fuelrespectively. Information relating to regulatory assets and gas cost adjustment clauses, net 40 61
Deferred environmental remediation costs 21 27
Asset retirement obligation - nuclear decommissioning 43 -
Deferred non-conventional fuel tax benefits, net (59) (40)
Storm damage reserve (36) (32)
Franchise agreements 62 65
Other 42 29
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total $208 $205
================================================================================liabilities follows.
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||
---|---|---|---|---|---|---|---|
Accumulated deferred income taxes, net | $ | 109 | $ | 110 | |||
Under-(over)-collections—electric fuel and gas cost adjustment clauses, net | (1 | ) | 38 | ||||
Deferred environmental remediation costs | 19 | 20 | |||||
Asset retirement obligation—nuclear decommissioning | 47 | 48 | |||||
Deferred non-conventional fuel tax benefits, net | (74 | ) | (67 | ) | |||
Storm damage reserve | (34 | ) | (37 | ) | |||
Franchise agreements | 60 | 62 | |||||
Non-legal asset retirement obligations | (353 | ) | (346 | ) | |||
Other | 25 | 21 | |||||
Total | $ | (202 | ) | $ | (151 | ) | |
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-collections -
Under-(over-) collections—fuel 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 North Carolina Utilities Commission (NCUC) during annual hearings.
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 South Carolina Electric & Gas Company (SCE&G) are being recovered through rates. Such costs, totaling approximately $11.6$9.8 million, are expected to be fully recovered by the end of 2005.2009. A portion of the costs incurred at sites owned by Public
Service Company of North Carolina, Incorporated (PSNC Energy) is also beingPSNC Energy has been recovered
through rates, and management believes the remaining costs of approximately $7.5$6.8 million will be recoverable. Amounts incurred and deferred to date that are not currently being recovered through gas rates at PSNC Energy are approximately $1.5$2.4 million. (See Note 3.)
Asset retirement obligation - obligation—nuclear decommissioning represents the regulatory asset associated with the legal obligation of decommissioningto decommission and dismantlingdismantle V. C. Summer Nuclear Station (Summer Station) as required inby SFAS 143, "Accounting for Asset Retirement Obligations." (See Note 1B.)
Deferred non-conventional fuel tax benefits, net represent the deferral of partnership losses and other expenses of approximately $44 million, offset by the accumulated deferred income tax credits of approximately $117 million associated with SCE&G's two partnerships involved in converting coal to alternatesynthetic fuel. Under a plan approved by the SCPSC, any net tax credits generated from non-conventional fuel produced by the partnerships and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership loseslosses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions.
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 actual incremental storm damage costs in excess of $2.5 million in a calendar year.
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 over approximately 15 years.
Non-legal 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.
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 the SCPSC or the NCUC.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 SCPSC or NCUCstate 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.
B. New Accounting Standards
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets,"
effective January 1, 2002. In connection with this implementation, the Company
performed a valuation analysis of its investment in South Carolina Pipeline
Corporation (SCPC) using a discounted cash flow analysis and of PSNC Energy
using an independent appraisal. The analysis of the investment in PSNC Energy
indicated that the carrying amount of PSNC Energy's acquisition adjustment
exceeded its fair value by approximately $230 million, or a $2.20 per share. The
resulting impairment charge is reflected on the Condensed Consolidated Statement
of Operations as the cumulative effect of an accounting change. SFAS 142
requires that an impairment evaluation be performed annually and at the same
time each year. The Company performed its annual evaluation as of January 1,
2003 and no further impairment was indicated.
The Company adopted SFAS 143 effective January 1, 2003. SFAS 143
applies to legal obligations associated with the retirement of tangible
long-lived assets (ARO) and requires the Company to recognize, as a liability,
the fair value of an ARO in the period in which it is incurred and to accrete
the liability to its present value in future periods. As of December 31, 2002,
prior to the adoption of SFAS 143, the Company carried deferred debits and
deferred credits each totaling approximately $87 million related to the
decommissioning and dismantling of Summer Station and the funding thereof.
Effective January 1, 2003, in connection with the measurement of the ARO upon
the adoption of SFAS 143, the amounts reflected within these regulatory assets
and liabilities were recharacterized.
The following table presents such recharacterized amounts related to the
decommissioning obligation and the funding thereof as recorded in the condensed
consolidated balance sheet as of September 30, 2003, and the pro forma amounts
that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been
adopted at the beginning of 2001.
As of
September 30, December 31, December 31,
Millions of dollars 2003 2002 2001
- -------------------
Actual Proforma Proforma
Assets:
Within electric plant $40 $40 $40
Within accumulated depreciation (13) (13) (12)
Assets held in trust (net) -
nuclear decommissioning 35 39 35
Within other regulatory assets 54 45 42
---------------- --------------- ---------------
---------------- --------------- ---------------
Total $116 $111 $105
================ =============== ===============
================ =============== ===============
Liabilities:
Asset retirement obligation -
nuclear plant decommissioning $116 $111 $105
================ =============== ===============
Proforma net income (loss) and earnings (loss) per share for periods
prior to the adoption of SFAS 143 would not differ from amounts actually
recorded during these periods.
The Company believes that there is legal uncertainty as to the existence
of environmental obligations associated with certain transmission and
distribution properties. The Company believes that any ARO related to this type
of property would be insignificant and, due to the indeterminate life of the
related assets, an ARO could not be reasonably estimated.
The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. The provisions of SFAS 145, among other things,
discontinue treatment of gains or losses from the early extinguishment of debt
as extraordinary items unless such early extinguishment meets the criteria of
Accounting Principles Board Opinion (APB) 30. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. This statement requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.
The Company adopted the disclosure provisions of SFAS 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure," effective January 1,
2003. SFAS 148 requires prominent disclosure in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of SFAS 148.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities".
SFAS 149 is effective for contracts entered into or modified after June 30, 2003
and for hedging relationships designated after June 30, 2003. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of SFAS 149.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope
as a liability (or an asset in some circumstances). SFAS 150 was effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
was effective at the beginning of the first interim period beginning after June
15, 2003. There was no impact on the Company's results of operations, cash flows
or financial position from the initial adoption of SFAS 150.
C. Equity Compensation Plan
Under the SCANA Corporation Long-Term Equity Compensation Plan (the "Plan")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 for Stock Issued to Employees"Employees," and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation" and effective January 1,
2003, the disclosure provisions of SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." At September 30, 2003, options issued
and outstanding under the Plan totaled approximately 1.5 million.
All options werehave been granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates;dates since the Plan's inception; therefore, no compensation expense has been recognized in connection with such grants. If the Company had determined to recognize
compensation expense for the issuance of options based on the fair value method described in SFAS 123, pro forma net income and earnings (loss) per share would have been as presented below:
| Three Months Ended March 31, | |||||
---|---|---|---|---|---|---|
| 2004 | 2003 | ||||
Net income—as reported (millions) | $ | 101.2 | $ | 83.6 | ||
Net income—pro forma (millions) | $ | 100.9 | $ | 83.2 | ||
Basic and diluted earnings per share—as reported | $ | .91 | $ | .75 | ||
Basic and diluted earnings per share—pro forma | $ | .91 | $ | .75 |
No options have been granted since 2002.
C. Pension and Other Postretirement Benefit Plans
Components of net periodic benefit income or cost recorded by the Company were as follows:
| | | Other Postretirement Benefits | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| Pension Benefits | |||||||||||
Three months ended March 31 (Millions of dollars) | ||||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||
Service cost | $ | 2.8 | $ | 2.6 | $ | 0.8 | $ | 1.3 | ||||
Interest cost | 9.1 | 9.5 | 2.9 | 3.8 | ||||||||
Expected return on assets | (17.7 | ) | (15.0 | ) | — | — | ||||||
Prior service cost amortization | 1.6 | 1.6 | 0.2 | 0.8 | ||||||||
Transition obligation amortization | 0.2 | 0.2 | 0.3 | 0.3 | ||||||||
Actuarial (gain) loss | — | 0.5 | 0.5 | 0.2 | ||||||||
Net periodic benefit (income) cost | $ | (4.0 | ) | $ | (0.6 | ) | $ | 4.7 | $ | 6.4 | ||
D. Earnings (Loss) Per Share
Earnings (loss) per share amounts have been computed in accordance with SFAS 128, "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 as 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.
E. Affiliated Transactions
SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. SCE&G had recorded as receivables from these affiliated companies for these investments approximately $15.4$17.8 million and $8.5$13.4 million at September 30, 2003March 31, 2004 and December 31, 2002,2003, respectively. SCE&G had recorded as payables to these affiliated companies for these investments approximately $14.3$15.6 million and $8.0$12.2 million at September 30, 2003March 31, 2004 and December 31, 2002,2003, respectively.
F. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003.
2. ACCOUNTING CHANGE
As a result of the January 1, 2002 adoption of SFAS 142, the Company
recorded a $230 million impairment charge related to the acquisition adjustment
recorded in connection with its investment in PSNC Energy. This charge is
reflected on the Condensed Consolidated Statements of Operations as the
cumulative effect of an accounting change. See additional information at Note
1B.
3. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company (SCE&G)
Electric
In January 2003 the SCPSC issued an order granting SCE&G a composite
increase in retail electric rates of approximately 5.8% which is 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 new rates were effective for service rendered on and after February 1, 2003.
As a part of the order, the SCPSC extended through 2005 its approval of the
accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the
plan, based on the level of revenues and operating expenses, 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.
In January 2003, in conjunction with the approval of the abovea retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component
to 1.678 cents per KWh. This reduction was effective for service rendered on and
after February 1, 2003. In April 2003 the SCPSC issued an order approving
SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per
KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's
purchasing practices and recognized the efficiency of SCE&G's electric
generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the appeal discussed below.of the SCPSC's May 2002 order. In May 2002 the SCPSC issued an order approvingapproved SCE&G's request to increase the fuel component of rates charged to electric customers, from 1.579
cents per KWh to 1.722 cents per KWh. The increasewhich reflected higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002. 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 certain purchased power costs. The appeal is still pending.
Circuit Court ruled that the current fuel clause only provides 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 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 portion of the purchased power costs not allowed to be recovered through the fuel clause.
In April 2004 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.678 cents per KWh to 1.821 cents 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 will be effective as of the first billing cycle in May 2004.
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, 20022003 through September 30, 2003March 31, 2004 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002
$.928 March-September 2003 $.728 November-December 2002
On October 28, 2003, as part of the annual review of gas costs, the
SCPSC approved SCE&G's request to decrease the cost of gas component from $.928
per therm to $.867 per therm effective with the first billing cycle in November
2003.
Rate Per Therm | Effective Date | ||
---|---|---|---|
$ | .728 | January–February 2003 | |
.928 | March–October 2003 | ||
.877 | November 2003–March 2004 |
The SCPSC allows SCE&G to recover through a billing surcharge to its 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 the billing surcharge from 3.0 cents per therm to 2.20.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at September 30, 2003March 31, 2004 of $11.6$9.8 million.
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, 20022003 through September 30, 2003March 31, 2004 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002
$.595
Rate Per Therm | Effective Date | ||
---|---|---|---|
$ | .460 | January–February 2003 | |
.595 | March 2003 | ||
.725 | April–November 2003 | ||
.600 | December 2003–March 2004 |
For service rendered on and after March 2003 $.215 February-June 2002
$.725 April-September 2003 $.350 July-October 2002
$.410 November-December 2002
On October 13, 2003 in connection with PSNC Energy's 2003 Annual
Prudence Review1, 2004, the NCUC determined thatauthorized PSNC Energy's gas costs, including all
hedging transactions, were reasonableEnergy to implement decrements in its sales and prudently incurred during the 12-month
review period ended March 31, 2003. The NCUC also authorized newtransportation rate decrementsschedules to refund overcollectionsreflect a decrease of certain gas costs includedapproximately $5.7 million in PSNC Energy's deferred accounts, effective November 1, 2003.annual fixed gas costs as well as the current over-recovery 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 would 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. PSNC Energy estimates that the cost of this project will be approximately $31.4$31 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion is expected to bewas completed and placed in the spring ofservice in April 2004. Through September 30,
2003March 31, 2004 approximately $24.4$29 million had been spent on this project.
In December 1999 the NCUC issued an order approving SCANA'sthe Company's acquisition of PSNC Energy. As specified in the order, PSNC Energy agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events.
South Carolina Pipeline Corporation (SCPC)
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In an order dated August 5, 2003
the SCPSC found that for the period April 2002 through December 2002 SCPC's gas
purchasing policies and practices were prudent and SCPC properly adhered to the
gas cost recovery provisions of its gas tariff.
4.
3. LONG-TERM DEBT
On January 13, 2003 the Company retired at maturity $60 million of 6.05%
medium-term notes.
On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds
having an annual interest rate of 5.80% and maturing on January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt and
for general corporate purposes.
On April 4, 2003 the Company redeemed $100 million of floating rate
medium-term notes that were set to mature August 8, 2003. The notes were bearing
interest at a rate of 2.215% when redeemed.
On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an
annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net
proceeds from the sale of these bonds and certain other SCE&G funds to redeem
its $100 million principal amount of 7.625% First Mortgage Bonds due June 1,
2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June
15, 2023 and its Junior Subordinated Debentures which effected the redemption of
$50 million aggregate amount of 7.55% Trust Preferred Securities, Series A,
issued by SCE&G Trust I.
On July 1, 2003 the Company retired at maturity $20 million of 6.51%
medium-term notes and, on July 8, 2003 the Company retired at maturity $75
million of 6.5% medium-term notes.
On August 26, 2003 Berkeley County, South Carolina, issued its
$35,850,000 Pollution Control Facilities Revenue Refunding Bonds, Series 2003.
The proceeds of these bonds were loaned by the County toFebruary 11, 2004 South Carolina Generating Company, Inc. (GENCO), issued $100 million of senior secured promissory notes maturing February 1, 2024 and applied to defease GENCO's obligation with
the respect to the County's $35,850,000 Pollution Control Facilities Revenue
Refunding Bonds, Series 1984 (bearing interest atbearing a rate of 6.50%). The 2003
refunding bonds have an annualfixed interest rate of 4.875%5.49%. Proceeds from this issuance were used to support GENCO's construction program and mature on October 1,
2014.
5.to repay intercompany advances borrowed for that purpose.
4. RETAINED EARNINGS
The 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, 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, 2003March 31, 2004 approximately $43.4$45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.
6.
5. FINANCIAL INSTRUMENTS
Investments
Certain of the Company'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. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established. At March 31, 2004 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held investments
Telecommunications Investments
At September 30, 2003The Company also holds investments in several partnerships and joint ventures, some of which are accounted for using the equity method. in the equity
and debt securities of the following companies in the amounts noted in the table
below.
Investee Securities Basis
- ---------------------- ------------------------------------------------------------- -----------------------
(Millions of dollars)
Magnolia Holding 6.2 million shares nonvoting common stock $2.1
ITC^DeltaCom 566.0 thousand shares of common stock 1.1
157.3 thousand shares series A 8% preferred stock,
convertible in 2005 into 2.8 million shares of common 13.0
stock
Warrants to purchase 506.9 thousand shares of common stock 1.1
Knology 7.2 million shares series A preferred stock, convertible
into
7.5 million shares of common stock 14.0
18.1 million shares series C preferred stock, convertible
into
18.1 million shares of common stock 33.9
21.7 million shares series E preferred stock, convertible
into
21.7 million shares of common stock 40.6
12% senior unsecured notes due 2009, including accrued 48.0
interest
In May 2003 the Company's investment in ITC Holding Company, Inc. was
sold and in September 2003 the working capital true-up for the sale was
completed. The transaction resulted in the receipt of net after-tax cash
proceeds of approximately $48 millionfollowing equity and the receipt of an investment interest
in a newly formed entity,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 | |||
163.6 thousand shares series A 8% preferred stock, convertible into 2.8 million shares of common stock | 13.2 | ||||
Warrants to purchase 506.9 thousand shares of common stock | 1.1 | ||||
Knology | 2.6 million shares of common stock | 23.1 | |||
2.2 million shares of nonvoting common stock | 19.6 | ||||
13% senior unsecured notes due 2009, including accrued interest | 51.1 | ||||
Warrants to purchase 16.5 thousand shares of common stock | — |
Magnolia Holding Company, LLC (Magnolia Holding). A
book gain, net of tax, of approximately $39 million was realized upon this
transaction. 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 $3.7 million, and the warrants owned have a market value of $3.1 million.$2.0 million as of March 31, 2004. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and thetheir market value is not readily determinable.
Knology, Inc. (Knology) is a broadband servicefully integrated provider of cable television, telephonevideo, voice, data and internet services.
In June 2003, based upon valuation information obtainedadvanced communication services to residential and business customers in connection with the Magnolia Holding transaction,southeastern United States. The common shares of Knology (voting and non-voting) owned by SCH recorded impairment losses associated withhad a market value of $32.6 million as of March 31, 2004.
Derivatives
The Company follows the Knology investment totaling $4.8 million, net of taxes.
In August 2003, Magnolia Holding distributed its holdings in Knology
preferred stock to Magnolia Holding's members. As a result, SCH's basis in
Magnolia Holding was reducedguidance required by and SCH's basis in Knology was increased by,
approximately $6.2 million.
Derivatives
SFASFAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, requires the Company to recognize all derivative
instruments as either assets or liabilities in the statement of financial
position and to measureaccounting for derivatives, including those instruments at fair value. SFAS 133 further
provides that changes in the fair value of derivative instruments are either
recognized in earnings or reported as a component of other comprehensive income
(loss), depending upon the intended use of the derivative and the resulting
designation. The fair value of the derivative instruments is determined by
reference to quoted market prices of listed contracts, published quotations or
quotationsarising from independent parties.
Policies and procedures and risk limits are established to control the
level of market, credit, liquidity and operational and administrative risks
assumed by the Company. The Company's Board of Directors has delegated to a Risk
Management Committee the authority to set risk limits, establish policies and
procedures for risk management and measurement, and oversee and review the risk
management process and infrastructure. The Risk Management Committee, which is
comprised of certain officers, including the Company's Risk Management Officer
and senior officers of the Company, apprises the Board of Directors with regard
to the management of risk and brings to the Board's attention any areas of
concern. Written policies define the physical and financial transactions that
are approved, as well as the authorization requirements and limits for
transactions.
Commodities
The Company uses derivative instruments to hedge anticipated future
purchases of natural gas, which create market risks of different types.
Instruments designated as cash flow hedges related to natural gas. The Company also utilizes swap agreements to manage interest rate risk. These transactions are usedmore fully described in Note 9 to hedge risks associated
with fixed price obligationsthe consolidated financial statements in a volatile price market and risks associated
with price differentials at different delivery locations. Instruments designated
as fair value hedges are used to hedge operational storage assets. The basic
types of financial instruments utilized are exchange-traded instruments, such as
New York Mercantile Exchange futures contracts or options, and over-the-counter
instruments such as swaps, which are typically offered by energy and financial
institutions.the Company's 2003 Form 10-K.
The Company recognized gains (losses) of approximately $(0.4)$1.9 million net of tax, and $5.4$5.6 million, net of tax, as a result of qualifying cash flow hedges related to nonregulated operationswhose hedged transactions occurred during the three months
ended March 31, 2004 and nine months ended
September 30, 2003. The Company recognized gains (losses) of approximately $0.1
million and $(21.9) million, net of tax, as a result of qualifying cash flow
hedges related to nonregulated operations during the three and nine months ended
September 30, 2002.2003, respectively. These gains and lossesamounts were recorded in cost of gas. The Company estimates that most of the September 30, 2003March 31, 2004 unrealized lossgain balance of $1.3$3.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2004 and 2005 as an increasea decrease to
realized gas cost if market prices remain stable. As of September 30, 2003March 31, 2004, all of the Company's cash flow hedges settle by their terms before the end of 2006.
The Company recorded option
Option premiums of $0.5 million and gains of $0.3
million, net of tax, as a result ofresulting from qualifying fair value hedges during the three and nine months ended September 30,March 31, 2004 and 2003 respectively. The premiumswere insignificant and
gains were recorded in cost of gas. As of September 30, 2003March 31, 2004 all of the Company's fair value hedges had settled.
In January 2003 PSNC Energy filed a summary of its hedging program for
natural gas purchases with the NCUC for informational purposes. The primary goal
of the program is to reduce price volatility to firm customers. In an October
2003 order, the NCUC declared the program was reasonable. Transaction fees and
any gains or losses are recorded in deferred accounts for subsequent rate
consideration. As of September 30, 2003 PSNC Energy had deferred a net gain of
approximately $0.6 million.
SCPC's tariffs include a purchased gas adjustment (PGA) clause that
provides for the recovery of actual gas costs incurred. The SCPSC has ruled that
the results of SCPC's hedging activities are to be included in the PGA. As such,
costs of related derivatives that SCPC utilizes to hedge its gas purchasing
activities are recoverable through its weighted average cost of gas calculation.
The offset to the change in fair value of these derivatives is recorded as a
current asset or liability.
Interest Rates
The Company uses interest rate swap agreements to manage interest rate
risk. These swap agreements provide for the Company to pay variable rate and
receive fixed rate interest payments and are designated as fair value hedges of
certain debt instruments. The Company may terminate a swap agreement and may
replace it with a new swap also designated as a fair value hedge.
Payments received upon termination of a swap are recorded as basis
adjustments to long-term debt and are amortized as reductions to interest
expense over the term of the underlying debt. The fair value of interest rate
swaps is recorded within other deferred debits on the balance sheet. The
resulting credits serve to reflect the hedged long-term debt at its fair value.
Periodic receipts or payments related to the interest rate swaps are credited or
charged to interest expense as incurred.
At September 30, 2003March 31, 2004 the estimated fair value of the Company's swaps totaled $12.1$14.3 million (gain) related to combined notional amounts of $337.4$333.1 million.
In anticipation of the issuance of debt, the Company also uses interest
rate lock or similar agreements to manage interest rate risks. Payments received
or made upon termination of such agreements are recorded within other deferred
debits on the balance sheet and are amortized to interest expense over the term
of the underlying debt. In connection with the issuance of First Mortgage Bonds
in May 2003, the Company paid approximately $11.9 million upon the termination
of a treasury lock agreement.
7.
6. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 12 of Notes10 to Consolidated Financial
Statementsthe consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.2003. Commitments and contingencies at September 30, 2003March 31, 2004 include the following:
A. Lake Murray Dam Reinforcement
In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that SCE&G reinforce its Lake Murray damDam in order to comply with new federal safety standards and maintain the lake in case of an extreme
earthquake.standards. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through September 30, 2003March 31, 2004 totaled approximately $126$192 million.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $10.9$10.8 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.
The
Congress failed to renew the Price-Anderson Indemnification Act was anticipated to renew in August
2002. However, Congress concluded their session in 2002 without approving this
renewal. The Act is now expected to renew with only modest changeswhen it expired in 2003. The delayed renewal has no impact on SCE&G at presentthe Company due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.
SCE&G currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) 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.
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. 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.
C. Environmental
The Company maintains an environmental assessment program to identify and evaluate current and former operations 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 amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $11.6$9.8 million at September 30, 2003.March 31, 2004. The deferral includes the estimated costs associated with the following matters.
SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of September 30, 2003,March 31, 2004, SCE&G has spent approximately $19.6$19.8 million to remediate the Calhoun Park site. Total remediation costs are estimatedsite and expects to be
$21.9spend an additional $2 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved 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. In addition, in March 2003 SCE&G signed a consent agreement with
DHEC related to a site formerly owned by SCE&G. The site contained residue
material that was moved from an MGP site. The removal action for this site has
been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of September 30, 2003,March 31, 2004, SCE&G has spent approximately $3.9$3.1 million related to these three sites, and expects to spend an additional $5.2$4.9 million. Total remediation costs are estimated to be
$9.1 million.
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 $7.5$6.8 million, which reflects the estimated remaining liability at September 30, 2003.March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $1.5$2.4 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.
D. Long-Term Natural Gas ContractClaims and Litigation
In 20011999 an unsuccessful bidder for the purchase of certain propane gas assets of SCANA Corporation (SCANA) filed suit against SCANA in Circuit Court, seeking unspecified damages. The
suit alleges the existence of a subsidiarycontract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company entered into, indoes not believe that the ordinary courseresolution of business,this issue will have a 15-year take-and-pay contract with an unaffiliated natural gas
supplier to purchase 190,000 DTmaterial impact on its results of natural gas per day beginning in the spring
of 2004. In December 2002,operations, cash flows or financial position.
On August 21, 2003, SCE&G was served as a resultco-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of the failure of the supplier and its
guarantor to meet contractual obligations related to credit support provisions,
the subsidiary terminated the contract and the supplier initiated arbitration. A
hearing under the binding arbitration provisions of the contract was postponed
from September 2003 until at least January 2004 after the parties made progress
towards a settlement. In initial pleadingsCommon Pleas for the hearing,Fifth Judicial Circuit. The plaintiffs are seeking damages for the supplier
demanded paymentalleged improper use of at least $134 million in damages fromelectric transmission easements but have not asserted a dollar amount for their claims. Specifically, the subsidiary;
conversely,plaintiffs contend that the subsidiary demanded paymentlicensing of no lessattachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than $154 million in
damages from the supplier.electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and will vigorously pursue its position if the arbitration hearing is
held.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.
E. Parts Availability Agreement
In June 2002
A complaint was filed on October 22, 2003 against SCE&G entered intoby 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 parts availability agreementmunicipality's limits. The complaint also alleges that SCE&G failed to obey, observe, or comply with a
supplier whereby turbine and stator bar parts will be stored by SCE&G to be
available when needed. The parts will remain the propertylawful order of the supplier until
such time as theySCPSC by charging franchise fees to those not residing within a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are removed from storage bythe subject of a similar lawsuit that was filed and served on SCE&G, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and payment is made.SCE&G. SCE&G bearsbelieves that the riskresolution of lossthese actions will not have a material adverse impact on its results of operations, cash flows or repair for any part damaged while in storage and will
pay an availability fee each quarter based on the daily available parts stored.financial condition. In addition, SCE&G is obligatedfiled a petition with the SCPSC on October 23, 2003 pursuant to purchase all remaining stored parts atS. C. Code Ann. R.103-836. The petition requests that the termination datesSCPSC exercise its jurisdiction to investigate the operation of the contract, June 2009 formunicipal 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 turbine partssystem which will reduce such errors in the future, and December
2006 forto adopt any regulation which the stator bar parts. As such, SCE&G has recorded a liabilitySCPSC deems just and proper to regulate the franchise fee collection process.
The Company is also engaged in Other
Long-Term Debt with an offsetting asset in Deferred Debits. At September 30,
2003 SCE&G had recorded $30.8 million forvarious other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the turbine parts and $3.2 million for
the stator bar parts.
8.Company.
7. 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, Gas Distribution and Gas Transmission segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Accumulated depreciation is not assignable to Electric Operations and
Gas Distribution segments; therefore, it is reflected as an adjustment to arrive
at the consolidated total assets. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation.
Three Months Ended March 31, 2004 | External Revenue | Intersegment Revenue | Operating Income | Net Income | Segment Assets | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Electric Operations | $ | 380 | $ | 1 | $ | 96 | n/a | $ | 5,134 | ||||||
Gas Distribution | 370 | 2 | 58 | n/a | 1,449 | ||||||||||
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 | 1 | 684 | ||||||||||
Adjustments/Eliminations | (13 | ) | (192 | ) | 33 | 80 | 773 | ||||||||
Consolidated Total | $ | 1,136 | $ | — | $ | 194 | $ | 101 | $ | 8,549 | |||||
March 31, 2003 | | | | | | ||||||||||
Electric Operations | $ | 336 | $ | 2 | $ | 84 | n/a | $ | 4,566 | ||||||
Gas Distribution | 343 | — | 61 | n/a | 1,416 | ||||||||||
Gas Transmission | 84 | 108 | 5 | n/a | 317 | ||||||||||
Retail Gas Marketing | 183 | — | n/a | $ | 13 | 124 | |||||||||
Energy Marketing | 123 | — | n/a | (2 | ) | 67 | |||||||||
All Other | 14 | 67 | — | (1 | ) | 601 | |||||||||
Adjustments/Eliminations | (14 | ) | (177 | ) | 18 | 74 | 1,086 | ||||||||
Consolidated Total | $ | 1,069 | $ | — | $ | 168 | $ | 84 | $ | 8,177 | |||||
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
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SCANA CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 (the(together with its consolidated subsidiaries, the Company) Annual Report on Form 10-K for the year ended December 31, 2002.2003.
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 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) changes in the utility and nonutility regulatory environment, (3) changes in the economy, especially in areas served by the Company's subsidiaries, (4) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (5) growth opportunities for the Company's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in the Company's accounting policies, (8) weather conditions, especially in areas served by the Company's subsidiaries, (9) performance of and marketability of the Company's investments in telecommunications companies, (10) performance of the Company's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the United States Securities and Exchange Commission. The Company disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina electric restructuring efforts remain stalled,April 2004 the joint U.S.-Canada Power System Outage Task Force issued its "Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report). The Blackout Report contains 46 recommendations that, if implemented, the state legislature adjourned forTask Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the year without considering electric
restructuring legislation. AtBlackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the federal level, energy legislationBlackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed both
houses of Congress in 2003, though significant differences exist between the House and Senate versions. Somein 2003 but have stalled in conference committee. Various provisions of the more stringent provisions of thisEnergy Bill related to electric reliability are being resubmitted as separate legislation either currently included or expected to be debated in conference
committee,(reliability legislation). It is anticipated that any reliability legislation, if passed, would require that one percentmake reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the electric energy sold by retail
electric suppliers, beginning in 2005, escalating to ten percent by 2020, be
generated from renewable energy resources. Renewable energy resources, as
defined in the legislation, may exclude hydroelectric generation. Substantial
penalties would be levied for failure to comply. Electric cooperatives and
municipal utilities would be exempt from these requirements. In addition,
largely in response to the August 2003 blackout in eight northern states and
parts of Canada, the energy legislation being considered includes several
provisions to develop and enforce reliability standards for high-voltage
transmission systems and to expedite construction of transmission lines. The
Company cannot predict whether such legislation will be enacted, and if it is,
the conditions it would impose on utilities.
In July 2002 the United StatesU.S. Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design
(SMD) which proposed sweeping changes, enabling it to enact regulatory initiatives that would significantly change 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. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could have a significant
impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside of its service territory.
In addition, the proposed ruleNorth American Electric Reliability Council (NERC) is expected to proceed with its initiatives to develop, establish and enforce standards for the grid. To that end, NERC is working 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 would be significantly influenced by any reliability legislation enacted by Congress. If implemented, such initiatives by FERC and NERC could have a significant impact on South Carolina
Electric and Gas Company's (SCE&G)SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory.
On April 28, 2003 FERC issued a "white paper" regarding SMD which describes how
the final SMD rule being considered would differ from the NOPR. The Company is
currently evaluating FERC's action to determine potential effects on SCE&G's
operations. Additional directives from FERC are expected, and would likely be
significantly influenced by the energy legislation discussed in the preceding
paragraph.
Retail Gas Distribution
Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, other household energy needs of residential
and small commercial customers. This competition is generally based on price and
convenience. Large commercial and industrial customers often have the ability to
switch fromMarketing
In March 2004 SCANA Energy acquired approximately 47,000 retail natural gas to an alternate fuel, such as propane or fuel oil.
Naturalcustomers formerly served by another gas competes with these alternate fuels based on price. Asmarketer in Georgia. With this transaction, SCANA Energy's total customer base represents about a result, any
significant disparity between supply and demand, either30 percent share of the 1.5 million customers in Georgia's natural gas or of
alternate fuels, and due either to production or delivery disruptions or other
factors, will affect price and impact the Company's ability to retain large
commercial and industrial customers.
Gas Transmission
In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC to
acquire an interest in an existing pipeline and to build a pipeline from Elba
Island, Georgia to Jasper County, South Carolina. When operational, SCG will
provide interstate transportation services for natural gas to markets in
southeastern Georgia and South Carolina. SCG will transport natural gas from
interconnections with Southern Natural at Port Wentworth, Georgia, and from an
import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia.
The endpoint of SCG's pipeline is at the site of the natural gas-fired
generating station that SCE&G is building in Jasper County, South Carolina.
Construction of the pipeline, which began in March 2003, was completed in the
third quarter of 2003 at a cost of approximately $32 million.
In August 2003 SCPC began construction on phase one of the South System
Loop pipeline project. This phase of the pipeline will stretch 38.3 miles from
SCE&G's Jasper County generation facility to Yemassee in Hampton County, South
Carolina, and will provide a new supply source to SCPC's current system.
Completion of phase one of the pipeline is expected in the first quarter of
2004, at a cost of approximately $25 million.
South Carolina Pipeline Corporation (SCPC) supplies natural gas to SCE&G
for its resale to gas distribution customers and for certain electric generation
needs. SCPC also sells natural gas to large commercial and industrial customers
in South Carolina and faces the same competitive pressures as gas distribution
for these classes of customers.
Retail Gas Marketingmarket. SCANA Energy continues to maintain its position asremains the second largest natural gas marketer in Georgia with a market share of approximately 25 percent
and total customers in excess of 380,000 (including those served under the program described below).state.
In March 2004 SCANA Energy's competitors include affiliates of other
large energy companies with substantial experience in Georgia's energy market as
well as several electric membership cooperatives (EMCs). SCANA's ability to
maintain its market share depends onterm for serving low-income and high credit risk customers was extended by the prices it charges customers relative toGPSC for an additional year (beginning September 1).
In November 2003 the prices charged by its competitors, its ability to continue to provide high
levels of customer service and other factors.
The Georgia Public Service Commission (GPSC) continues to implement
provisions of the Natural Gas Consumer's Relief Act of 2002 (the Act). Among
other things, the Act createdfiled a regulated provider selected through a bidding
process to serve low-income and high credit risk customers. The Act also
established new service quality standards and addressed assignment of interstate
assets.
In 2002 SCANA Energy was selected by the GPSC to serve as Georgia's
regulated provider for a 2-year period. In this capacity, SCANA Energy serves
low-income customers at a rate subsidized by Georgia's Universal Service Fund,
and extends service to high credit risk customers who have been denied service
by other marketers. At September 30, 2003 approximately 31,000 of SCANA Energy's
total customers were being served under this program.
In July 2003 the GPSC approved a joint stipulation between the GPSC
staff, Atlanta Gas Light Company (AGL) and natural gas marketers (excluding
SCANA Energy) dealing with interstate asset capacity and other operational
issues. The joint stipulation reduces the frequency whereby AGL can recall
capacity previously released to the various gas marketers and streamlines
certain gas balancing processes. Though SCANA Energy believes the joint
stipulation will improve operations for the gas marketers, SCANA Energy
continues to advocate an alternate plan it proposed that would assign interstate
asset capacity to those gas marketers choosing assignment and approved by the
GPSC. The GPSC has indicated that it intends to file a requestpetition with FERC to
obtainseeking a declaratory order on the assignment of interstate capacity. That petition addressed the question of whether FERC regulation would preempt or have
jurisdiction over SCANA Energy's proposal. The GPSC has not yet filed the
request with FERC. If FERC issues a declaratory order, the GPSC is expectedif a plan proposed by SCANA Energy for the assignment of Atlanta Gas Light Company's interstate capacity assets to evaluatecertificated natural gas marketers was adopted by the orderGPSC. On April 15, 2004 FERC ruled that it continues to maintain jurisdiction and determine what action, if any,would preempt the GPSC should take on
SCANA Energy's proposal.
SCANA's other naturaldoes not expect that FERC's ruling will have any negative impact on operations.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2004
AS COMPARED TO THE CORRESPONDING PERIOD IN 2003
Earnings Per Share
Reported (GAAP) earnings per share of common stock for the periods ended March 31, 2004 and 2003 were as follows:
| First Quarter | |||||
---|---|---|---|---|---|---|
| 2004 | 2003 | ||||
Reported (GAAP) earnings per share | $ | .91 | $ | .75 | ||
Reported (GAAP) earnings per share increased by $.16 due to improved electric margins of $.15, improved gas distribution, transmissionmargins of $.09, lower interest expense of $.01 and marketing segments maintain gas inventorya reduction of preferred dividend requirements of $.01. These factors were partially offset by higher operation and also utilize forward contractsmaintenance expenses of $.06, higher property taxes of $.02 and higher depreciation and amortization expense of $.02.
Pension Income
Pension income was recorded on the Company's financial instruments, including futures contracts and options,statements as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||
2004 | 2003 | |||||||
Income Statement Impact: | ||||||||
Reduction in (component of) employee benefit costs | $ | 1.1 | $ | (1.0 | ) | |||
Other income | 2.5 | 1.9 | ||||||
Balance Sheet Impact: | ||||||||
Reduction in (component of) capital expenditures | 0.3 | (0.3 | ) | |||||
Component of amount due to Summer Station co-owner | 0.1 | — | ||||||
Total Pension Income | $ | 4.0 | $ | 0.6 | ||||
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 in the first quarter of 2004 increased compared to manage
their exposure to fluctuating commodity natural gas prices. Asthe corresponding period in 2003 primarily as a partresult of this
risk management process, at any given time,a more favorable investment market.
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of SCANA's projectedthe 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. The increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project (see discussion at CAPITAL PROJECTS).
Dividends Declared
The Company's Board of Directors has declared the following dividends on common stock during 2004:
Declaration Date | Dividend Per Share | Record Date | Payment Date | ||||
---|---|---|---|---|---|---|---|
February 19, 2004 | $ | .365 | March 10, 2004 | April 1, 2004 | |||
April 29, 2004 | $ | .365 | June 10, 2004 | July 1, 2004 |
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:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Operating revenues | $ | 379.9 | 13.1 | % | $ | 336.0 | ||
Less: Fuel used in generation | 95.4 | 18.1 | % | 80.8 | ||||
Purchased power | 12.7 | 21.0 | % | 10.5 | ||||
Margin | $ | 271.8 | 11.1 | % | $ | 244.7 | ||
Margin increased primarily due to increased retail electric base rates that went into effect in February 2003, for a total impact of $7.1 million, an additional $3.2 million due to favorable weather, $14.6 million from off-system sales and $2.2 million due to customer growth and consumption.
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:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Operating revenues | $ | 371.7 | 8.3 | % | $ | 343.3 | ||
Less: Gas purchased for resale | 264.2 | 14.1 | % | 231.5 | ||||
Margin | $ | 107.5 | (3.9 | )% | $ | 111.8 | ||
Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and maintenance) and an unfavorable competitive position of natural gas needs has been purchased or otherwise placed under contract. Sincerelative to alternate fuels of $1.6 million, partially offset by customer growth and increased consumption of $0.5 million.
Gas Transmission
Gas Transmission is comprised of the operations of South Carolina Pipeline Corporation (SCPC). Gas transmission sales margins (including transactions with affiliates) were as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Operating revenues | $ | 172.3 | (10.5 | )% | $ | 192.4 | ||
Less: Gas purchased for resale | 157.7 | (12.1 | )% | 179.4 | ||||
Margin | $ | 14.6 | 12.3 | % | $ | 13.0 | ||
Margin increased primarily due to higher transportation revenue as a result of new customers of $1.8 million, partially offset by an unfavorable competitive position of natural gas relative to alternate fuels of $0.5 million.
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:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Operating revenues | $ | 217.7 | 18.5 | % | $ | 183.7 | ||
Net income | $ | 20.6 | 55.8 | % | $ | 13.2 |
Operating revenues increased primarily as a competitive market, it may be unableresult of increased volumes and higher average retail prices. Net income increased primarily due to sustain its
current levelshigher margins of customers and/or pricing, thereby reducing expected$8.9 million partially offset by increased bad debt expense of $1.2 million.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net loss were as follows:
| First Quarter | ||||||||
---|---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | ||||||
Operating revenues | $ | 115.2 | (6.0 | )% | $ | 122.4 | |||
Net loss | $ | (0.5 | ) | 74.6 | % | $ | (1.8 | ) |
Operating revenues decreased primarily as a result of decreased volumes. Net loss decreased primarily due to improved gas margins of $1.7 million.
Other Operating Expenses
Other operating expenses were as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Other operation and maintenance | $ | 154.6 | 7.3 | % | $ | 144.1 | ||
Depreciation and amortization | 62.7 | 4.7 | % | 59.9 | ||||
Other taxes | 38.8 | 12.5 | % | 34.5 | ||||
Total | $ | 256.1 | 7.4 | % | $ | 238.5 | ||
Other operation and profitability.
maintenance expenses increased primarily due to increased labor and benefit costs of $5.8 million, increased bad debt expenses of $2.0 million, 2004 winter storm restoration expenses of $2.5 million and increased expense at electric generation plants of $3.4 million, partially offset by decreased recovery of environmental remediation expenses of $3.2 million (offset in gas margin) and increased pension income of $2.1 million. Depreciation and amortization increased due to normal net property changes. Other taxes increased primarily due to increased property taxes.
Other Income (Expense)
Other income, including AFC, decreased primarily due to reduced other non-operating income partially offset by an increase in AFC due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project.
Income Taxes
Income taxes increased primarily as a result of changes in operating 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. Salesindebtedness and sales of additional equity securities may
also occur.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 September 30, 2003March 31, 2004 was 1.87.2.95.
Cash requirements for SCANA'sthe Company's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA.SCANA Corporation. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity or 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, if requested.
In January 2003 the Public Service Commission of South Carolina (SCPSC)
issued an order granting SCE&G a composite increase in retail electric rates of
approximately 5.8% which is 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 new rates were effective for
service rendered on and after February 1, 2003. As a part of the order, the
SCPSC extended through 2005 its approval of the accelerated capital recovery
plan for SCE&G's Cope Generating Station. Under the plan, based on the level of
revenues and operating expenses, 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 the 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 the Company generated and used funds for property additions and construction expenditures during the ninethree months ended September 30, 2003March 31, 2004 and 2002:
- ----------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions2003:
| Three Months Ended March 31, | ||||||
---|---|---|---|---|---|---|---|
Millions of dollars | |||||||
2004 | 2003 | ||||||
Net cash provided from operating activities | $ | 163 | $ | 155 | |||
Net cash provided from financing activities | 67 | 4 | |||||
Cash and temporary investments available at the beginning of the period | 117 | 341 | |||||
Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction | $ | 122 | $ | 171 | |||
Funds used for nonutility property additions | 4 | 3 | |||||
Funds used for investments | (3 | ) | (4 | ) |
SCE&G intends to file an electric rate case with the SCPSC in the summer of dollars 2003 2002
- -------------------------------------------------------------- -------------
Net cash provided from operating activities $399 $347
Net cash used for financing activities (187) (242)
Cash provided from sale2004 requesting, among other things, recovery of investments and assets 69 335
Funds used for investments (11) (25)
Cash and temporary investments availablecapital expenditures related to the generating facility in Jasper County, South Carolina. This filing will also include SCE&G's plan to use synthetic fuel tax credits to offset
construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the beginningfiling within six months of the period 374 192
Funds used for utility property additions and
construction expenditures,
net of noncash allowance for funds used
during construction $(558) $(424)
Funds used for nonutility property additions (6) (12)
CAPITAL TRANSACTIONS
On January 13, 2003 SCANA retired at maturity $60February 11, 2004 GENCO issued $100 million of 6.05%
medium-term notes.
On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds
having an annualsenior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.80% and maturing on January 15, 2033. The
proceeds5.49%. Proceeds from the sale of these bondsthis issuance were used to reduce short-term debt and
for general corporate purposes.
On April 4, 2003 SCANA redeemed $100 million of floating rate
medium-term notes that were set to mature August 8, 2003. The notes were bearing
interest at a rate of 2.215% when redeemed.
On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an
annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net
proceeds from the sale of these bonds and certain other SCE&G funds to redeem
its $100 million principal amount of 7.625% First Mortgage Bonds due June 1,
2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June
15, 2023 and its Junior Subordinated Debentures which effected the redemption of
$50 million aggregate amount of 7.55% Trust Preferred Securities, Series A,
issued by SCE&G Trust I.
On July 1, 2003 SCANA retired at maturity $20 million of 6.51%
medium-term notes, and on July 8, 2003 SCANA retired at maturity $75 million of
6.25% medium-term notes.
On August 26, 2003 Berkeley County, South Carolina, issued its
$35,850,000 Pollution Control Facilities Revenue Refunding Bonds, Series 2003.
The proceeds of these bonds were loaned by the County to South Carolina
Generating Company, Inc. (GENCO), and applied to defeasesupport GENCO's obligation with
the respect to the County's $35,850,000 Pollution Control Facilities Revenue
Refunding Bonds, Series 1984 (bearing interest at a rate of 6.50%). The 2003
refunding bonds have an annual interest rate of 4.875% and mature on October 1,
2014.
On November 6, 2003 SCE&G issued $250 million First Mortgage Bonds
having an annual interest rate of 5.25% and maturing on November 1, 2018. SCE&G
will use the net proceeds from the sale of these bonds for the payment at
maturity of SCE&G's $100 million principal amount of 6.25% First Mortgage Bonds
due December 15, 2003, for repayment of short-term debt primarily incurred as a
result of SCE&G's construction program and to repay intercompany advances borrowed for general corporate purposes.
that purpose.
Effective May 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 2 million new shares of common stock and provide approximately $65 million in additional common stock equity on an annual basis. In addition, effective April 29, 2004 SCANA discontinued purchasing outstanding shares of common stock on the open market.
CAPITAL PROJECTS
In May 2002
Construction of SCE&G began construction of an&G's 875 megawatt generation facility in Jasper County, South Carolina to supply electricity to its South
Carolina customers.has been completed. The facility will includeincludes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility is expected to beginbegan commercial operation in mid-2004. SCG will
transport natural gasMay 2004. Approximately $276 million of the capital expenditures have been included in rate base, and the remainder are expected to be included in the facility. Costs incurred through September 30, 2003
totaled approximately $421 million.rate case previously discussed.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray damDam in order to comply with new federal safety standards and maintain the lake in
case of an extreme earthquake.standards. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through September 30, 2003March 31, 2004 totaled approximately $126$192 million.
In 2002 SCE&G entered into 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 above 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, 2003 SCE&G had not
yet borrowed under the agreement.
In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC
to acquire an interest in an existing pipeline and to build a pipeline from Elba
Island, Georgia to Jasper County, South Carolina. When operational, SCG will
provide interstate transportation services for natural gas to markets in
southeastern Georgia and South Carolina. SCG will transport natural gas from
interconnections with Southern Natural at Port Wentworth, Georgia, and from an
import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia.
The endpoint of SCG's pipeline is at the site of the natural gas-fired
generating station that SCE&G is building in Jasper County, South Carolina.
Construction of the pipeline, which began in March 2003,SCPC's South System Loop was completed in the
third quarter of 2003March 2004 at a cost of approximately $32$21 million. In August 2003 SCPC began construction on phase one of the South System
LoopThis pipeline project. This phase of the pipeline will stretchstretches 38.3 miles from SCG Pipeline's connection with SCE&G's Jasper County generation facility to Yemassee in Hampton County, South Carolina, and will provideproviding a new supply source to SCPC's current system.
Completion of phase one of the pipeline is expected in the first quarter of
2004, at a cost of approximately $25 million.
ENVIRONMENTAL MATTERS
For information on environmental matters see Note 7C of Notes6C to Condensed Consolidated Financial Statements.
condensed consolidated financial statements.
OTHER MATTERS
Nuclear Station License Extension
In August 2002 SCE&G filed an application withApril 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). If approved, theThe extension would allowallows the plant to operate through 2042. At September 30, 2003 SCE&G has capitalized in
construction work in progress approximately $7 million related to the
application process and expects to capitalize an additional $2 million. SCE&G
expects the extension to be issued in mid-2004.
Telecommunications Investments
In May 2003 the Company's investment in ITC Holding Company, Inc. was
sold and in September 2003 the working capital true-up for the sale was
completed. The transaction resulted in the receipt of net after-tax cash
proceeds of approximately $48 million and the receipt of an investment interest
in a newly formed entity, Magnolia Holding Company LLC (Magnolia Holding). A
book gain, net of tax, of approximately $39 million was realized upon this
transaction.
In August 2003, Magnolia Holding distributed its holdings in Knology
preferred stock to Magnolia Holding's members. As a result, SCH's basis in
Magnolia Holding was reduced by, and SCH's basis in Knology was increased by,
approximately $6.2 million.
Synthetic Fuel
SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of September 30, 2003March 31, 2004 is approximately $3 million, and through September 30, 2003,March 31, 2004, they have generated and passed through to SCE&G approximately $83$107 million in such tax credits. At September 30, 2003March 31, 2004 SCE&G has recorded $59on its balance sheet $74 million ofnet deferred
fuel tax benefits, which include partnership losses, net of tax. In addition, PrimeSouth,Primesouth, Inc, a non-regulated subsidiary of SCANA, operates a synthetic fuel facility for a third party and receives management fees, royalties and expense reimbursements related to these services. PrimeSouthPrimesouth does not benefit from any synfuel tax credits.
Under a plan approved by the SCPSC, any tax credits generated 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 will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A of Notes to Consolidated
Financial Statements.
On June 27, 2003the condensed consolidated financial statements.
In March 2004 the Company received a "No Change" letter from the Internal Revenue Service (IRS) announced that it
is reviewing the scientific validity of certain test procedures and results that
have been presented as evidence that solid coal-based synthetic fuels have
undergone a significant chemical change. Pending completion of this review, the
IRS suspended the issuance of Private Letter Rulings on the question of
significant chemical change for requests that rely on the testing procedures and
results being reviewed. Upon finishing this review, on October 29, 2003, the IRS
issued Announcement 2003-70, finishing its review, and confirming that the test
procedures and results used by taxpayers are scientifically valid if the
procedures are applied in a consistent and unbiased manner.related to SCE&G believes its
test procedures will meet the standards contemplated&G's interest in the Announcement.
Although one ofsynthetic fuel partnership S. C. Coaltech No. l L.P. for the partnerships in which SCE&G owns an interest is currently
under audit bytax year 2000. This letter supports the IRS, there have been no issues raised with respect toCompany's position that the
validity of synthetic fuel tax credits. While SCE&G is not able to determine
what conclusion the IRS will reach in these matters, to the extent the IRS
disallows synfuel tax credits generated by either of the two partnerships or the
facility managed by PrimeSouth, the Company's and SCE&G's financial position,
results of operations and cash flows would not be materially adversely affected.
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003
AS COMPARED TO THE CORRESPONDING PERIODS IN 2002
The following discussion of the results of operations of SCANA
Corporation and its subsidiaries (the Company) includes a non-GAAP measure,
GAAP-adjusted net earnings from operations per share, which excludes from net
income (loss) (i) the cumulative effects of mandated changes in accounting
principles and (ii) the effects of sales of certain assets and investments and
impairment charges related to certain investments. Management believes that
GAAP-adjusted net earnings from operations provides a meaningful representation
of the Company's fundamental earnings power and improves comparability of
period-over-period financial performance.
Earnings Per Share
GAAP-adjusted net earnings from operations per share of common stock for
the third quarter and year to date periods ended September 30, 2003 and 2002
were as follows:
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held for purposes other than trading.
Interest rate risk - 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.
As of March 31, 2004 | Expected Maturity Date | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars Liabilities | 2004 | 2005 | 2006 | 2007 | 2008 | There- After | Total | Fair Value | |||||||||
Long-Term Debt: | |||||||||||||||||
Fixed Rate ($) | 197.9 | 193.6 | 174.4 | 68.6 | 158.6 | 2,640.9 | 3,434.0 | 3,484.1 | |||||||||
Average Fixed Interest Rate (%) | 7.53 | 7.39 | 8.50 | 6.96 | 6.13 | 6.24 | 6.60 | ||||||||||
Variable Rate ($) | 200.0 | 200.0 | 200.0 | ||||||||||||||
Average Variable Interest Rate (%) | 1.57 | 1.57 | |||||||||||||||
Interest Rate Swaps: | |||||||||||||||||
Pay Variable/Receive Fixed ($) | 57.5 | 3.2 | 3.2 | 28.2 | 118.2 | 122.8 | 333.1 | 14.3 | |||||||||
Average Pay Interest Rate (%) | 5.84 | 4.30 | 4.30 | 4.31 | 2.81 | 2.97 | 3.55 | ||||||||||
Average Receive Interest Rate (%) | 7.70 | 8.75 | 8.75 | 7.11 | 5.89 | 6.51 | 6.59 |
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.
At September 30, 2003March 31, 2004 the Company held investments in the 12%13% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $48$51.1 million. As these notes are not activelybroadly traded, determination of their fair value is not practicable.
In June 2002 SCE&G entered into a parts availability agreement with a
supplier whereby turbine and stator bar parts will be stored by SCE&G to be
available when needed. The parts will remain the property of the supplier until
such time as they are removed from storage by SCE&G and payment is made. SCE&G
bears the risk of loss or repair for any part damaged while in storage and will
pay an availability fee each quarter based on the daily available parts stored.
In addition, SCE&G is obligated to purchase all remaining stored parts at the
termination dates of the contract, June 2009 for the turbine parts and December
2006 for the stator bar parts. As such, SCE&G has recorded a liability in Other
Long-Term Debt with an offsetting asset in Deferred Debits. At September 30,
2003 SCE&G had recorded $30.8 million for the turbine parts and $3.2 million for
the stator bar parts.
Commodity price risk - risk—The following table provides information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value represents quoted market prices.
Expected Maturity:
| Futures Contracts | | Options | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2004 | Long ($) | Short ($) | | Purchased call (long) ($) | Purchased put (short) ($) | |||||
Settlement Price(a) | 6.05 | 6.01 | ||||||||
Contract Amount | 16.5 | 2.4 | Strike Price(a) | 4.86 | — | |||||
Fair Value | 20.0 | 2.6 | Contract Amount | 6.8 | — | |||||
2005 | ||||||||||
Settlement Price(a) | 5.89 | 6.44 | ||||||||
Contract Amount | 5.3 | 0.2 | Strike Price(a) | — | — | |||||
Fair Value | 6.5 | 0.2 | Contract Amount | — | — | |||||
2006 | ||||||||||
Settlement Price(a) | 5.66 | — | ||||||||
Contract Amount | 0.5 | — | Strike Price(a) | — | — | |||||
Fair Value | 0.7 | — | Contract Amount | — | — |
Equity price risk - 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 $94.8$40.4 million at September 30, 2003.March 31, 2004. A temporary decline in value of ten percent would result in a $9.5$4.0 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 $9.5$4.0 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.
Item 4. Controls and Procedures
As of September 30, 2003March 31, 2004 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, 2003March 31, 2004 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, 2003March 31, 2004 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
Item 1. Financial Statements
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ------------------------------------------------------------------------------ ------------------- -----------------------
September 30, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------ ------------------- -----------------------
Assets
Utility Plant:
Electric $5,098 $4,934
Gas 453 439
Other 181 184
- ------------------------------------------------------------------------------ ------------------- -----------------------
Total 5,732 5,557
Accumulated depreciation and amortization (2,009) (1,912)
- ------------------------------------------------------------------------------ ------------------- -----------------------
Total 3,723 3,645
Construction work in progress 877 604
Nuclear fuel, net of accumulated amortization 41 38
- ------------------------------------------------------------------------------ ------------------- -----------------------
Utility Plant, Net 4,641 4,287
- ------------------------------------------------------------------------------ ------------------- -----------------------
Nonutility Property and Investments, Net 25 25
- ------------------------------------------------------------------------------ ------------------- -----------------------
- ------------------------------------------------------------------------------ ------------------- -----------------------
Current Assets:
Cash and temporary investments 25 56
Receivables, net 226 237
Receivables - affiliated companies 64 46
Inventories (at average cost):
Fuel 27 48
Materials and supplies 52 53
Emission allowances 7 10
Prepayments 20 24
- ------------------------------------------------------------------------------ ------------------- -----------------------
Total Current Assets 421 474
- ------------------------------------------------------------------------------ ------------------- -----------------------
Deferred Debits:
Environmental 12 18
Nuclear plant decommissioning - 87
Assets held in trust, net - nuclear decommissioning 35 -
Pension asset, net 269 265
Due from affiliates - pension and postretirement benefits 20 18
Other regulatory assets 296 267
Other 146 103
- ------------------------------------------------------------------------------ ------------------- -----------------------
Total Deferred Debits 778 758
- ------------------------------------------------------------------------------ ------------------- -----------------------
Total $5,865 $5,544
============================================================================== =================== =======================
- --------------------------------------------------------------------------------- ----------------- --------------------
September 30, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------- ----------------- --------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,028 $1,966
Preferred stock (Not subject to purchase or sinking funds) 106 106
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Stockholders' Investment 2,134 2,072
Preferred Stock, net (Subject to purchase or sinking funds) 9 9
Company-Obligated Mandatorily Redeemable Preferred Securities of the Company's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55%
Junior Subordinated Debentures of SCE&G - 50
Long-Term Debt, net 1,706 1,534
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Capitalization 3,849 3,665
- --------------------------------------------------------------------------------- ----------------- --------------------
Current Liabilities:
Short-term borrowings 196 178
Current portion of long-term debt 238 144
Accounts payable 82 124
Accounts payable - affiliated companies 63 77
Customer deposits 24 22
Taxes accrued 100 93
Interest accrued 35 31
Dividends declared 39 42
Deferred income taxes, net 4 12
Other 23 37
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Current Liabilities 804 760
- --------------------------------------------------------------------------------- ----------------- --------------------
Deferred Credits:
Deferred income taxes, net 650 610
Deferred investment tax credits 111 108
Reserve for nuclear plant decommissioning - 87
Asset retirement obligation - nuclear plant 116 -
Due to affiliates - pension and postretirement benefits 15 17
Postretirement benefits 133 131
Regulatory liabilities 133 109
Other 54 57
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Deferred Credits 1,212 1,119
- --------------------------------------------------------------------------------- ----------------- --------------------
Total $5,865 $5,544
================================================================================= ================= ====================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- ---------------------------------------------------------------- -------------------------- -------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars 2003 2002 2003 2002
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Operating Revenues:
Electric $430 $425 $1,125 $1,079
Gas 54 47 258 207
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Total Operating Revenues 484 472 1,383 1,286
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Operating Expenses:
Fuel used in electric generation 78 86 218 217
Purchased power (including affiliated purchases) 42 36 107 111
Gas purchased for resale 44 36 194 148
Other operation and maintenance 93 89 296 269
Depreciation and amortization 47 43 142 126
Other taxes 30 27 90 81
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Total Operating Expenses 334 317 1,047 952
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Operating Income 150 155 336 334
Other Income, Including Allowance for Equity Funds
Used During Construction of $5, $5, $13 and $16 9 9 24 28
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 159 164 360 362
Interest Charges, Net of Allowance for Borrowed
Funds Used During Construction of $3, $3, $7 and $10 30 30 97 87
Dividend Requirement of Company -
Obligated Mandatorily Redeemable Preferred Securities - 1 2 3
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Income Before Income Taxes and Preferred Stock Dividends 129 133 261 272
Income Tax Expense 41 47 86 94
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Net Income 88 86 175 178
Preferred Stock Cash Dividends Declared (At stated rates) 2 2 6 6
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Earnings Available for Common Stockholder $86 $84 $169 $172
================================================================ ============ ============= ============= ===========
See Notes to Condensed Consolidated Financial Statements.
o
40
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -------------------------------------------------------------------------------------------- ----------------------------
Nine Months Ended
September 30,
Millions of dollars 2003 2002
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash Flows From Operating Activities:
Net income $175 $178
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization 141 127
Amortization of nuclear fuel 18 14
Allowance for funds used during construction (20) (26)
Over (under) collections, fuel adjustment clauses 26 (14)
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net (7) (27)
(Increase) decrease in inventories 25 (7)
(Increase) decrease in prepayments 4 (8)
(Increase) decrease in pension asset (4) (20)
(Increase) decrease in other regulatory assets (20) (1)
Increase (decrease) in deferred income taxes, net 32 14
Increase (decrease) in regulatory liabilities 34 32
Increase (decrease) in postretirement benefits obligations 2 7
Increase (decrease) in accounts payable (56) (40)
Increase (decrease) in taxes accrued 7 (11)
Increase (decrease) in interest accrued 4 4
Changes in other assets 4 (15)
Changes in other liabilities 8 3
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Provided From Operating Activities 373 210
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (451) (362)
Proceeds from sales of assets - 1
Increase in nonutility property - (2)
Increase in investments (11) (7)
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Used For Investing Activities (462) (370)
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 495 295
Capital contribution from parent 2 5
Repayments:
Mortgage Bonds (250) (104)
Pollution Control Bonds (6) -
Other long-term debt (12) (3)
SCE&G Trust 1 Preferred Securities (50) -
Retirement of preferred stock - (1)
Payment of deferred financing costs (21) -
Dividends and distributions:
Common stock (112) (113)
Preferred stock (6) (6)
Short-term borrowings, net 18 84
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Provided From Financing Activities 58 157
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Decrease In Cash and Temporary Investments (31) (3)
Cash and Temporary Investments, January 1 56 37
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash and Temporary Investments, September 30 $25 $34
============================================================================================ ============= ==============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $7 and $10) $93 $82
- Income taxes 22 54
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||||
---|---|---|---|---|---|---|---|---|---|
Assets | |||||||||
Utility Plant: | |||||||||
Electric | $ | 5,616 | $ | 5,558 | |||||
Gas | 459 | 456 | |||||||
Common | 196 | 193 | |||||||
Total | 6,271 | 6,207 | |||||||
Accumulated depreciation and amortization | (1,937 | ) | (1,907 | ) | |||||
Total | 4,334 | 4,300 | |||||||
Construction work in progress | 989 | 951 | |||||||
Nuclear fuel, net of accumulated amortization | 36 | 42 | |||||||
Utility Plant, Net | 5,359 | 5,293 | |||||||
Nonutility Property and Investments, Net | 26 | 25 | |||||||
Current Assets: | |||||||||
Cash and temporary investments | 79 | 56 | |||||||
Receivables, net | 230 | 238 | |||||||
Receivables—affiliated companies | 42 | 61 | |||||||
Inventories (at average cost): | |||||||||
Fuel | 30 | 35 | |||||||
Materials and supplies | 56 | 54 | |||||||
Emission allowances | 13 | 6 | |||||||
Prepayments | 25 | 20 | |||||||
Deferred income taxes, net | 4 | — | |||||||
Total Current Assets | 479 | 470 | |||||||
Deferred Debits: | |||||||||
Environmental | 10 | 11 | |||||||
Assets held in trust, net—nuclear decommissioning | 46 | 44 | |||||||
Pension asset, net | 274 | 270 | |||||||
Due from affiliates—pension and postretirement benefits | 21 | 20 | |||||||
Other regulatory assets | 310 | 333 | |||||||
Other | 139 | 145 | |||||||
Total Deferred Debits | 800 | 823 | |||||||
Total | $ | 6,664 | $ | 6,611 | |||||
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||
---|---|---|---|---|---|---|---|
Capitalization and Liabilities | |||||||
Shareholders' Investment: | |||||||
Common equity | $ | 2,059 | $ | 2,043 | |||
Preferred stock (Not subject to purchase or sinking funds) | 106 | 106 | |||||
Total Shareholders' Investment | 2,165 | 2,149 | |||||
Preferred Stock, net (Subject to purchase or sinking funds) | 9 | 9 | |||||
Long-Term Debt, net | 2,110 | 2,010 | |||||
Total Capitalization | 4,284 | 4,168 | |||||
Minority Interest | 75 | 100 | |||||
Current Liabilities: | |||||||
Short-term borrowings | 191 | 140 | |||||
Current portion of long-term debt | 142 | 142 | |||||
Accounts payable | 93 | 104 | |||||
Accounts payable—affiliated companies | 91 | 134 | |||||
Customer deposits | 25 | 25 | |||||
Taxes accrued | 48 | 101 | |||||
Interest accrued | 40 | 39 | |||||
Dividends declared | 38 | 43 | |||||
Deferred income taxes, net | — | 8 | |||||
Other | 24 | 34 | |||||
Total Current Liabilities | 692 | 770 | |||||
Deferred Credits: | |||||||
Deferred income taxes, net | 720 | 707 | |||||
Deferred investment tax credits | 114 | 114 | |||||
Asset retirement obligation—nuclear plant | 119 | 118 | |||||
Due to affiliates—pension and postretirement benefits | 15 | 15 | |||||
Postretirement benefits | 136 | 135 | |||||
Regulatory liabilities | 446 | 429 | |||||
Other | 63 | 55 | |||||
Total Deferred Credits | 1,613 | 1,573 | |||||
Commitments and Contingencies | — | — | |||||
Total | $ | 6,664 | $ | 6,611 | |||
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
| Three Months Ended March 31, | ||||||
---|---|---|---|---|---|---|---|
Millions of dollars | |||||||
2004 | 2003 | ||||||
Operating Revenues: | |||||||
Electric | $ | 381 | $ | 337 | |||
Gas | 146 | 140 | |||||
Total Operating Revenues | 527 | 477 | |||||
Operating Expenses: | |||||||
Fuel used in electric generation | 95 | 81 | |||||
Purchased power (including affiliated purchases) | 13 | 10 | |||||
Gas purchased for resale | 111 | 100 | |||||
Other operation and maintenance | 108 | 104 | |||||
Depreciation and amortization | 52 | 49 | |||||
Other taxes | 35 | 31 | |||||
Total Operating Expenses | 414 | 375 | |||||
Operating Income | 113 | 102 | |||||
Other Income, Including Allowance for Equity Funds Used During Construction of $5 and $4 | 6 | 7 | |||||
Income Before Interest Charges, Minority Interest, Income Taxes and Preferred Stock Dividends | 119 | 109 | |||||
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction of $3 and $2 | 35 | 34 | |||||
Dividend Requirement of Company—Obligated Mandatorily Redeemable Preferred Securities | — | 1 | |||||
Income Before Minority Interest, Income Taxes and Preferred Stock Dividends | 84 | 74 | |||||
Minority Interest | 2 | 2 | |||||
Income Before Income Taxes and Preferred Stock Dividends | 82 | 72 | |||||
Income Tax Expense | 28 | 25 | |||||
Net Income | 54 | 47 | |||||
Preferred Stock Cash Dividends Declared (At stated rates) | 2 | 2 | |||||
Earnings Available for Common Shareholder | $ | 52 | $ | 45 | |||
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| Three Months Ended March 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||||
2004 | 2003 | |||||||||
Cash Flows From Operating Activities: | ||||||||||
Net income | $ | 54 | $ | 47 | ||||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||||
Minority interest | 2 | 2 | ||||||||
Depreciation and amortization | 52 | 49 | ||||||||
Amortization of nuclear fuel | 6 | 6 | ||||||||
Allowance for funds used during construction | (8 | ) | (6 | ) | ||||||
Over collections, fuel adjustment clauses | 32 | 22 | ||||||||
Changes in certain assets and liabilities: | ||||||||||
(Increase) decrease in receivables, net | 27 | (1 | ) | |||||||
(Increase) decrease in inventories | (4 | ) | 15 | |||||||
(Increase) decrease in prepayments | (5 | ) | 3 | |||||||
(Increase) decrease in pension asset | (4 | ) | (1 | ) | ||||||
(Increase) decrease in other regulatory assets | 2 | — | ||||||||
Increase (decrease) in deferred income taxes, net | 1 | (1 | ) | |||||||
Increase (decrease) in regulatory liabilities | 4 | 9 | ||||||||
Increase (decrease) in postretirement benefits obligations | 1 | 3 | ||||||||
Increase (decrease) in accounts payable | (54 | ) | (22 | ) | ||||||
Increase (decrease) in taxes accrued | (53 | ) | (41 | ) | ||||||
Increase (decrease) in interest accrued | 1 | 5 | ||||||||
Changes in other assets | (1 | ) | (21 | ) | ||||||
Changes in other liabilities | — | (2 | ) | |||||||
Net Cash Provided From Operating Activities | 53 | 66 | ||||||||
Cash Flows From Investing Activities: | ||||||||||
Utility property additions and construction expenditures, net of AFC | (107 | ) | (155 | ) | ||||||
Increase in nonutility property | (1 | ) | — | |||||||
Investments in affiliates | (3 | ) | (4 | ) | ||||||
Net Cash Used For Investing Activities | (111 | ) | (159 | ) | ||||||
Cash Flows From Financing Activities: | ||||||||||
Proceeds: | ||||||||||
Issuance of First Mortgage Bonds | — | 198 | ||||||||
Issuance of notes | 100 | — | ||||||||
Dividends and distributions: | ||||||||||
Common stock | (41 | ) | (40 | ) | ||||||
Preferred stock | (2 | ) | (2 | ) | ||||||
Distribution to parent | (27 | ) | — | |||||||
Short-term borrowings, net | 51 | (64 | ) | |||||||
Net Cash Provided From Financing Activities | 81 | 92 | ||||||||
Net Increase (Decrease) In Cash and Temporary Investments | 23 | (1 | ) | |||||||
Cash and Temporary Investments, January 1 | 56 | 23 | ||||||||
Cash and Temporary Investments, March 31 | $ | 79 | $ | 22 | ||||||
Supplemental Cash Flow Information: | ||||||||||
Cash paid for—Interest (net of capitalized interest of $3 and $2) | $ | 35 | $ | 30 | ||||||
—Income taxes | — | — |
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2003
March 31, 2004
(Unaudited)
The following notes should be read in conjunction with the Notes to Consolidated Financial Statements appearing in South Carolina Electric & Gas Company's (the Company) Annual Report on Form 10-K for the year ended December 31, 2002.2003. 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
A. Variable Interest Entity
The Company adopted Financial Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46), "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. The Company has determined that it has a controlling financial interest in South Carolina Generating Company, Inc. (GENCO) under the criteria of FIN 46, and accordingly, the accompanying condensed consolidated financial statements include the accounts of the Company, GENCO and South Carolina Fuel Company, Inc. Prior period amounts have been restated to reflect the adoption of FIN 46. The consolidation resulted in an increase of approximately $336 million in net assets reflected in the condensed consolidated balance sheet for March 31, 2004. The equity interest in GENCO is held solely by SCANA Corporation, the Company's parent. Accordingly, GENCO'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.
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 the Company under the terms of a power purchase and related agreement. Substantially all of GENCO's property (carrying value of approximately $75 million) serves as collateral for its long-term borrowings.
B. Basis of Accounting
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 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 the Company has recorded, as of September 30, 2003,March 31, 2004, approximately $308
$320 million and $133$446 million of regulatory assets (including environmental) and liabilities, respectively, as shown below.
September 30, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Accumulated deferred income taxes, net $86 $86
Under-collections - electric fuelrespectively. Information relating to regulatory assets and gas cost adjustment clauses, net 24 50
Deferred environmental remediation costs 12 18
Asset retirement obligation - nuclear decommissioning 43 -
Deferred non-conventional fuel tax benefits, net (59) (40)
Storm damage reserve (36) (32)
Franchise agreements 62 65
Other 43 29
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total $175 $176
================================================================================liabilities follows.
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||
---|---|---|---|---|---|---|---|
Accumulated deferred income taxes, net | $ | 103 | $ | 104 | |||
Under-(over-)collections—electric fuel and gas cost adjustment clauses, net | 7 | 39 | |||||
Deferred environmental remediation costs | 10 | 11 | |||||
Asset retirement obligation—nuclear decommissioning | 47 | 48 | |||||
Deferred non-conventional fuel tax benefits, net | (74 | ) | (67 | ) | |||
Storm damage reserve | (34 | ) | (37 | ) | |||
Franchise agreements | 60 | 62 | |||||
Non-legal asset retirement obligations | (270 | ) | (265 | ) | |||
Other | 25 | 20 | |||||
Total | $ | (126 | ) | $ | (85 | ) | |
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-collections -
Under-(over-)collections—fuel 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) during annual hearings.
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 the Company are being recovered through rates. Such costs, totaling approximately $11.6$9.8 million, are expected to be fully recovered by the end of 2005.2009.
Asset retirement obligation - obligation—nuclear decommissioning represents the regulatory asset associated with the legal obligation of decommissioningto decommission and dismantlingdismantle V. C. Summer Nuclear Station (Summer Station) as required inby SFAS 143, "Accounting for Asset Retirement Obligations." (See Note 1B).
Deferred non-conventional fuel tax benefits, net represent the deferral of partnership losses and other expenses of approximately $44 million, offset by the accumulated deferred income tax credits of approximately $117 million associated with the Company's two partnerships involved in converting coal to alternatesynthetic fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced by the partnerships and consumed by the Company and ultimately passed through to the Company, net of partnership losses and other expenses, have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions.
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 actual storm damage costs in excess of $2.5 million in a calendar year.
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 over approximately 15 years.
Non-legal 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.
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 the Company. 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.
B. New Accounting Standards
The Company adopted SFAS 143 effective January 1, 2003. SFAS 143
applies to legal obligations associated with the retirement of tangible
long-lived assets (ARO) and requires the Company to recognize, as a liability,
the fair value of an ARO in the period in which it is incurred and to accrete
the liability to its present value in future periods. As of December 31, 2002,
prior to the adoption of SFAS 143, the Company carried deferred debits and
deferred credits each totaling approximately $87 million related to the
decommissioning and dismantling of Summer Station and the funding thereof.
Effective January 1, 2003, in connection with the measurement of the ARO upon
the adoption of SFAS 143, the amounts reflected within these regulatory assets
and liabilities were recharacterized.
The following table presents such recharacterized amounts related to
the decommissioning obligation and the funding thereof as recorded in the
condensed consolidated balance sheet as of September 30, 2003, and the pro forma
amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS
143 been adopted at the beginning of 2001.
As of
September 30, December 31, December 31,
Millions of dollars 2003 2002 2001
- -------------------
Actual Proforma Proforma
Assets:
Within electric plant $40 $40 $40
Within accumulated depreciation (13) (13) (12)
Assets held in trust (net) -
nuclear decommissioning 35 39 35
Within other regulatory assets 54 45 42
-------------- --------------- -------------
-------------- --------------- -------------
Total $116 $111 $105
============== =============== =============
============== =============== =============
Liabilities:
Asset retirement obligation -
nuclear plant decommissioning $116 $111 $105
================ =============== ===========
Proforma net income for periods prior to the adoption of SFAS 143 would
not differ from amounts actually recorded during these periods.
The Company believes that there is legal uncertainty as to the existence
of environmental obligations associated with certain transmission and
distribution properties. The Company believes that any ARO related to this type
of property would be insignificant and, due to the indeterminate life of the
related assets, an ARO could not be reasonably estimated.
The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. The provisions of SFAS 145, among other things,
discontinue treatment of gains or losses from the early extinguishment of debt
as extraordinary items unless such early extinguishment meets the criteria of
Accounting Principles Board Opinion (APB) 30. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. This statement requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope
as a liability (or an asset in some circumstances). SFAS 150 was effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
was effective at the beginning of the first interim period beginning after June
15, 2003. There was no impact on the Company's results of operations, cash flows
or financial position from the initial adoption of SFAS 150.
C. Affiliated Transactions
The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The Company purchases all of its natural gas requirements from South Carolina Pipeline Corporation (SCPC). The Company had approximately $15.8$26.8 million and $29.6$39.5 million payable to SCPC for such gas purchases at September
30, 2003March 31, 2004 and December 31, 2002, respectively. The Company purchases all of the
electric generation of Williams Station, which is owned by South Carolina
Generating Company (GENCO), under a unit power sales agreement. The Company had
approximately $8.7 million and $9.0 million, payable to GENCO for unit power
purchases at September 30, 2003 and December 31, 2002, respectively. Such unit
power purchases, which are included in "Purchased power", amounted to
approximately $28.9 million and $68.2 million for the three and nine months
ended September 30, 2003, respectively.
The Company holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. The Company had recorded as receivables from these affiliated companies for these investments approximately $15.4$17.8 million and $8.5$13.4 million at September 30, 2003March 31, 2004 and December 31, 2002,2003, respectively. The Company had recorded as payables to these affiliated companies for
these investments approximately $14.3$15.6 million and $8.0$12.2 million at September 30,
2003March 31, 2004 and December 31, 2002,2003, respectively.
D. Pension and Other Postretirement Benefit Plans
Components of net periodic benefit income or cost recorded by the Company were as follows:
| | | Other Postretirement Benefits | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Pension Benefits | ||||||||||||
Three months ended March 31 (Millions of dollars) | |||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||
Service cost | $ | 2.8 | $ | 2.6 | $ | 0.8 | $ | 1.3 | |||||
Interest cost | 9.1 | 9.5 | 2.9 | 3.8 | |||||||||
Expected return on assets | (17.7 | ) | (15.0 | ) | — | — | |||||||
Prior service cost amortization | 1.6 | 1.6 | 0.2 | 0.8 | |||||||||
Transition obligation amortization | 0.2 | 0.2 | 0.3 | 0.3 | |||||||||
Actuarial (gain) loss | — | 0.5 | 0.5 | 0.2 | |||||||||
Amount attributable to company affiliates | (0.4 | ) | (0.5 | ) | (0.9 | ) | (1.2 | ) | |||||
Net periodic benefit (income) cost | $ | (4.4 | ) | $ | (1.1 | ) | $ | 3.8 | $ | 5.2 | |||
E. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003.
2. RATE AND OTHER REGULATORY MATTERS
Electric
In January 2003 the SCPSC issued an order granting the Company a
composite increase in retail electric rates of 5.8% which is 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 new
rates were effective for service rendered on and after February 1, 2003. As a
part of the order, the SCPSC extended through 2005 its approval of the
accelerated capital recovery plan for the Company's Cope Generating Station.
Under the plan, based on the level of revenues and operating expenses, the
Company 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.
In January 2003, in conjunction with the approval of the abovea retail rate increase, the SCPSC approved the Company's request to reduce the fuel
component to 1.678 cents per KWh. This reduction was effective for service
rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order
approving the Company's request to maintain the fuel cost component of rates at
1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the
prudence of the Company's purchasing practices and recognized the efficiency of
the Company's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the appeal discussed below.of the SCPSC's May 2002 order. In May 2002 the SCPSC issued an order approvingapproved the Company's request to increase the fuel component of rates charged to electric customers, from 1.579
cents per KWh to 1.722 cents per KWh. The increasewhich reflected higher fuel costs projected for
the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of the Company's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002.2000–2001. 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 certain purchased power costs. The appeal is still pending.
Circuit Court ruled that the current fuel clause only provides 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 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 portion of the purchased power costs not allowed to be recovered through the fuel clause.
In April 2004 the SCPSC approved SCE&G's request to increase the fuel component of rates charged to electric customers from 1.678 cents per KWh to 1.821 cents 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 will be effective as of the first billing cycle in May 2004.
Gas
The Company'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 the Company.
The Company's cost of gas component in effect during the period January 1, 20022003 through September 30, 2003March 31, 2004 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002
$.928 March-September 2003 $.728 November-December 2002
On October 28, 2003, as part of the annual review of gas costs, the
SCPSC approved the Company's request to decrease the cost of gas component from
$.928 per therm to $.867 per therm effective with the first billing cycle in
November 2003.
Rate Per Therm | Effective Date | ||
---|---|---|---|
$ | .728 | January–February 2003 | |
.928 | March–October 2003 | ||
.877 | November 2003–March 2004 |
The SCPSC allows the Company to recover, through a billing surcharge to its gas customers, the costs of environmental cleanup at the sites of former manufactured gas plants (MGPs).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 the Company's gas operations that had previously been recorded in deferred debits. In October 2003, as a result of the annual review, the SCPSC approved the Company's request to reduce the billing surcharge from 3.0 cents per therm to 2.20.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at September 30, 2003March 31, 2004 of $11.6$9.8 million.
3. LONG-TERM DEBT
On January 23, 2003 the CompanyFebruary 11, 2004 GENCO issued $200$100 million of First Mortgage
Bonds having an annualsenior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.80% and maturing on January 15, 2033.
The proceeds5.49%. Proceeds from the sale of these bondsthis issuance were used to reduce short-term debtsupport GENCO's construction program and to repay intercompany advances borrowed for general corporate purposes.
On May 21, 2003 the Company issued $300 million First Mortgage Bonds
having an annual interest rate of 5.30% and maturing on May 15, 2033. The
Company used the net proceeds from the sale of these bonds and certain other
Company funds to redeem its $100 million principal amount of 7.625% First
Mortgage Bonds due June 1, 2023, its $150 million principal amount of 7.50%
First Mortgage Bonds due June 15, 2023 and its Junior Subordinated Debentures
which effected the redemption of $50 million aggregate amount of 7.55% Trust
Preferred Securities, Series A, issued by SCE&G Trust I.
In anticipation of the issuance of debt, the Company also uses interest
rate lock or similar agreements to manage interest rate risks. Payments received
or made upon termination of such agreements are recorded within other deferred
debits on the balance sheet and are amortized to interest expense over the term
of the underlying debt. In connection with the issuance of First Mortgage Bonds
in May 2003, the Company paid approximately $11.9 million upon the termination
of a treasury lock agreement.
that purpose.
4. RETAINED EARNINGS
The Company's Restated Articles of Incorporation contain provisions that, under certain circumstances, 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, 2003March 31, 2004 approximately $43.4$45.3 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
5. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 11 of Notes10 to Consolidated Financial
Statementsthe consolidated financial statements appearing in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.2003. Commitments and Contingencies at September 30, 2003March 31, 2004 include the following:
A. Lake Murray Dam Reinforcement
In October 1999 the United States Federal Energy Regulatory Commission (FERC) mandated that the Company reinforce its Lake Murray damDam in order to comply with new federal safety standards and maintain the lake in case of an
extreme earthquake.standards. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through September 30, 2003March 31, 2004 totaled approximately $126$192 million.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $10.9$10.8 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. The Company'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.
The
Congress failed to renew the Price-Anderson Indemnification Act was anticipated to renew in
August 2002. However, Congress concluded their session in 2002 without approving
this renewal. The Act is now expected to renew with only modest changeswhen it expired in 2003. The delayed renewal has no impact on SCE&G at presentthe Company due to the "grandfathered" status of existing licensees that are covered under the expired Act until such time as it is renewed.
The Company currently maintains policies (for itself and on behalf of the South Carolina Public Service Authority) 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, the Company's portion of the retrospective premium assessment would not exceed $15.8 million.
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 the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. 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.
C. Environmental
The Company maintains an environmental assessment program to identify and evaluate current and former operations 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 the Company, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $11.6$9.8 million at September 30, 2003.March 31, 2004. The deferral includes the estimated costs associated with the following matters.
The Company owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed by the end of 2004, with certain monitoring and retreatment activities continuing until 2007. As of September 30, 2003,March 31, 2004, the Company has spent approximately $19.6$19.8 million to remediate the Calhoun Park site. Total remediation costs are
estimatedsite and expects to be $21.9spend an additional $2 million.
The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. In addition, in March 2003
the Company signed a consent agreement with DHEC related to a site formerly
owned by the Company. The site contained residue material that was moved from
the Columbia MGP. The removal action for this site has been completed.South Carolina Department of Health and Environmental Control (DHEC). The Company is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. The Company anticipates that major remediation activities for the three owned sites will be completed before 2006. As of September 30, 2003,March 31, 2004, the Company has spent approximately $3.9$3.1 million related to these three sites, and expects to spend an additional $5.2$4.9 million.
Total remediation costs are estimated to be $9.1 million
D. Parts Availability Agreement
In June 2002Claims and Litigation
On August 21, 2003, the Company entered intowas served as a parts availability agreement
withco-defendant in a supplier whereby turbinepurported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and stator bar partsSouth Carolina Electric & Gas Company, 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 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 line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. The Company further believes that the resolution of these claims will be storednot have a material adverse impact on its results of operations, cash flows or financial condition.
A complaint was filed on October 22, 2003 against the Company by the State of South Carolina alleging that the Company violated the Unfair Trade Practices Act by charging municipal franchise fees to be available when needed.some customers residing outside a municipality's limits. The parts will remaincomplaint also alleges that the propertyCompany failed to obey, observe, or comply with the lawful order of the supplier until such time as theySCPSC by charging franchise fees to those not residing in a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. The Company is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are removed from storage bythe subject of a similar lawsuit that was filed and served on the Company, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and payment is made.the Company. The Company bearsfurther believes that the riskresolution of lossthese actions will not have a material adverse impact on its results of operations, cash flows or repair for any part
damaged while in storage and will pay an availability fee each quarter based on
the daily available parts stored.financial condition. In addition, the Company is obligatedfiled a petition with the SCPSC on October 23, 2003 pursuant to purchase all remaining parts atS. C. Code Ann. R.103-836. The petition requests that the termination datesSCPSC exercise its jurisdiction to investigate the operation of the contract, June 2009
formunicipal franchise fee collection requirements applicable to the turbine partsCompany's electric and December 2006 forgas service, to approve the stator bar stored parts. AsCompany'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 which the SCPSC deems just and proper to regulate the franchise fee collection process.
The Company has recorded a liabilityis also engaged in Other Long-Term Debt with an
offsetting asset in Deferred
Debits. At September 30, 2003various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company had recorded $30.8 million for the
turbine parts and $3.2 million for the stator bar parts.
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. Accumulated depreciation is not assignable to
Electric Operations and Gas Distribution segments; therefore, it is reflected as
an adjustment to arrive at the consolidated total assets. Intersegment revenues were not significant.
| 2004 | 2003 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Three Months Ended March 31, | External Revenue | Operating Income | Segment Assets | External Revenue | Operating Income | Segment Assets | ||||||||||||
Electric Operations | $ | 381 | $ | 97 | $ | 5,080 | $ | 337 | $ | 84 | $ | 4,587 | ||||||
Gas Distribution | 146 | 16 | 325 | 140 | 18 | 315 | ||||||||||||
Adjustments/Eliminations | — | — | 1,259 | — | — | 1,156 | ||||||||||||
Consolidated Total | $ | 527 | $ | 113 | $ | 6,664 | $ | 477 | $ | 102 | $ | 6,058 | ||||||
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
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 (SCE&G) Annual Report on Form 10-K for the year ended December 31, 2002.2003.
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 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) changes in the utility regulatory environment, (3) changes in the economy, especially in SCE&G's service territory, (4) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (5) growth opportunities, (6) the results of financing efforts, (7) changes in SCE&G's accounting policies, (8) weather conditions, especially in areas served by SCE&G, (9) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on SCE&G's results of operations, (10) inflation, (11) changes in environmental regulations and (12) the other risks and uncertainties described from time to time in SCE&G's periodic reports filed with the United States Securities and Exchange Commission. SCE&G disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina electric restructuring efforts remain stalled,April 2004 the joint U.S.-Canada Power System Outage Task Force issued its "Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations" (Blackout Report). The Blackout Report contains 46 recommendations that, if implemented, the state legislature adjourned forTask Force believes would improve reliability of North America's interconnected bulk power system (the grid). Full implementation of the year without considering electric
restructuring legislation. AtBlackout Report's recommendations would require a number of actions by legislative, regulatory and industry participants. However, the federal level, energy legislationBlackout Report asserts as its single most important recommendation that the U.S. Congress should enact the reliability provisions contained in the Energy Bill, different versions of which passed both
houses of Congress in 2003, though significant differences exist between the House and Senate versions. Somein 2003 but have stalled in conference committee. Various provisions of the more stringent provisions of thisEnergy Bill related to electric reliability are being resubmitted as separate legislation either currently included or expected to be debated in conference
committee,(reliability legislation). It is anticipated that any reliability legislation, if passed, would require that one percentmake reliability standards mandatory and enforceable with penalties for non-compliance and would strengthen the role of the electric energy sold by retail
electric suppliers, beginning in 2005, escalating to ten percent by 2020, be
generated from renewable energy resources. Renewable energy resources, as
defined in the legislation, may exclude hydroelectric generation. Substantial
penalties would be levied for failure to comply. Electric cooperatives and
municipal utilities would be exempt from these requirements. In addition,
largely in response to the August 2003 blackout in eight northern states and
parts of Canada, the energy legislation being considered includes several
provisions to develop and enforce reliability standards for high-voltage
transmission systems and to expedite construction of transmission lines. SCE&G
cannot predict whether such legislation will be enacted, and if it is, the
conditions it would impose on utilities.
In July 2002 the United StatesU.S. Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design
(SMD) which proposed sweeping changes, enabling it to enact regulatory initiatives that would significantly change 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. The Company cannot predict whether Congress will enact reliability legislation or the extent to which the other recommendations contained in the Blackout Report will be implemented. If implemented, such legislation could have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside of its service territory.
In addition, the proposed ruleNorth American Electric Reliability Council (NERC) is expected to proceed with its initiatives to develop, establish and enforce standards for the grid. To that end, NERC is working 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 would be significantly influenced by any reliability legislation enacted by Congress. If implemented, such initiatives by FERC and NERC could have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. On April 28,
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2004
AS COMPARED TO THE CORRESPONDING PERIOD IN 2003 FERC issued
Net Income
Net income for the periods ended March 31, 2004 and 2003 was as follows:
| First Quarter | |||||
---|---|---|---|---|---|---|
Millions of dollars | ||||||
2004 | 2003 | |||||
Net income | $ | 53.8 | $ | 47.0 |
Net income increased due to higher electric margins of $16.6 million and a "white
paper" regarding SMD which describes how the final SMD rule being considered
would differ from the NOPR. SCE&G is currently evaluating FERC's actions to
determine potential effectsreduction of preferred dividend requirements of $0.9 million, partially offset by lower gas margins of $3.1 million, higher operation and maintenance expense of $3.1 million, higher depreciation expense of $1.6 million, higher property taxes of $2.4 million and higher interest expense of $0.7 million.
Pension Income
Pension income was recorded on SCE&G's operations. Additional directives from
FERC are expected, and would likely be significantly influenced byfinancial statements as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||
2004 | 2003 | |||||||
Income Statement Impact: | ||||||||
Reduction in (component of) employee benefit costs | $ | 1.4 | $ | (0.7 | ) | |||
Other income | 2.5 | 2.0 | ||||||
Balance Sheet Impact: | ||||||||
Reduction in (component of) capital expenditures | 0.4 | (0.2 | ) | |||||
Component of amount due to Summer Station co-owner | 0.1 | — | ||||||
Total Pension Income | $ | 4.4 | $ | 1.1 | ||||
For the energy
legislation discussedlast several years, the market value of SCANA's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. SCE&G's portion of SCANA's pension income in the preceding paragraph.
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. SCE&G 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. The increase in AFC for the three months ended March 31, 2004 is primarily due to construction expenditures related to the Jasper County Generating Station Project and the Lake Murray Dam Project (see discussion at CAPITAL PROJECTS).
Dividends Declared
SCE&G and GENCO's Board of Directors has declared the following dividends on common stock held by SCANA during 2004:
Declaration Date | Amount | Quarter Ended | Payment Date | ||||
---|---|---|---|---|---|---|---|
February 19, 2004 | $ | 36.0 million | March 31, 2004 | April 1, 2004 | |||
April 29, 2004 | $ | 37.0 million | June 30, 2004 | July 1, 2004 |
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and South Carolina Fuel Company, Inc. Electric operations sales margins were as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Operating Revenues | $ | 381.1 | 13.0% | $ | 337.4 | |||
Less: Fuel used in generation | 95.4 | 18.1% | 80.8 | |||||
Purchased power | 12.7 | 21.0% | 10.5 | |||||
Margin | $ | 273.0 | 10.9% | $ | 246.1 | |||
Margin increased primarily due to increased retail electric base rates that went into effect in February 2003 for a total impact of $7.1 million, an additional $3.2 million due to favorable weather, $14.6 million from off-system sales and $2.0 million due to customer growth and consumption.
Gas Distribution
Gas Distribution Natural gas competesis comprised of the local distribution operations of SCE&G. Gas distribution sales margins (including transactions with electricity, propaneaffiliates) were as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||
2004 | % Change | 2003 | ||||||
Operating Revenues | $ | 145.7 | 4.0% | $ | 140.1 | |||
Less: Gas purchased for resale | 110.8 | 10.6% | 100.2 | |||||
Margin | $ | 34.9 | (12.5)% | $ | 39.9 | |||
Margin decreased primarily due to decreased recovery of environmental remediation expenses of $3.2 million (offset in operations and heating oil to serve
the heatingmaintenance) and to a lesser extent, other household energy needs of residential
and small commercial customers. This competition is generally based on price and
convenience. Large commercial and industrial customers often have the ability to
switch from natural gas to an alternate fuel, such as propane or fuel oil.
Natural gas competes with these alternate fuels based on price. As a result, any
significant disparity between supply and demand, eitherunfavorable competitive position of natural gas or ofrelative to alternate fuels of $1.9 million.
Other Operating Expenses
Other operating expenses were as follows:
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Other operation and maintenance | $ | 108.7 | 4.8% | $ | 103.7 | |||
Depreciation and amortization | 51.9 | 5.3% | 49.3 | |||||
Other taxes | 35.0 | 12.5% | 31.1 | |||||
Total | $ | 195.6 | 6.3% | $ | 184.1 | |||
Other operation and maintenance expenses increased primarily due either to production or delivery disruptions orincreased labor and benefit costs of $2.4 million, 2004 winter storm restoration expenses of $2.5 million and increased expenses at electric generation plants of $3.4 million, partially offset by decreased recovery of environmental remediation expenses of $3.2 million (offset in gas margin) and increased pension income of $2.1 million. Depreciation and amortization expense increased primarily due to normal net property changes. Other taxes increased primarily due to increased property taxes.
Other Income
Other income, including AFC, decreased primarily due to reduced other factors, will affect pricenon-operating income partially offset by an increase in AFC due to construction expenditures related to the Jasper County Generation Station Project and impact SCE&G's abilitythe Lake Murray Dam Project.
Interest Expense
Interest expense increased by $3.9 million due to retain large commercialincreased long-term debt partially offset by $2.1 million due to lower interest rates and industrial customers.
by $1.0 million due to increased AFC.
Income Taxes
Income taxes increased primarily as a result of changes in operating income.
LIQUIDITY AND CAPITAL RESOURCES
SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months ended March 31, 2004 was 3.07.
SCE&G's cash requirements arise primarily from its operational needs, funding its construction programs and payment of dividends to SCANA. The ability of SCE&G 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. SCE&G's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief, if requested.
In January 2003 the Public Service Commission of South Carolina (SCPSC)
issued an order granting SCE&G a composite increase in retail electric rates of
5.8% which is 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 new rates were effective for service rendered on
and after February 1, 2003. As a part of the order, the SCPSC extended through
2005 its approval of the accelerated capital recovery plan for SCE&G's Cope
Generating Station. Under the plan, based on the level of revenues and operating
expenses, 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 the 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 ninethree months ended September 30, 2003March 31, 2004 and 2002:
- -------------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions2003:
| Three Months Ended March 31, | ||||||
---|---|---|---|---|---|---|---|
Millions of dollars | |||||||
2004 | 2003 | ||||||
Net cash provided from operating activities | $ | 53 | $ | 66 | |||
Net cash provided from financing activities | 81 | 92 | |||||
Funds used for investments | (3 | ) | (4 | ) | |||
Cash and temporary cash investments available at the beginning of the period | 56 | 23 | |||||
Funds used for utility property additions and construction expenditures, net of noncash allowance for funds used during construction | $ | 107 | $ | 155 | |||
Funds used for nonutility property additions | 1 | — |
SCE&G intends to file an electric rate case with the SCPSC in the summer of dollars 2003 2002
- -------------------------------------------------------------------- ----------
Net cash provided from operating activities $373 $210
Net cash provided from financing activities 58 157
Cash provided from sale2004 requesting, among other things, recovery of assets - 1
Funds used for investments (11) (7)
Cash and temporary cash investments availablecapital expenditures related to the generating facility in Jasper County, South Carolina. This filing will also include SCE&G's plan to use synthetic fuel tax credits to offset construction costs of SCE&G's reinforcement dam at Lake Murray. The SCPSC would be expected to render its decision on the beginningfiling within six months of the period 56 37
Funds used for utility property additions and
construction expenditures, net of
noncash allowance for funds used during construction $(451) $(362)
Funds used for nonutility property additions - (2)
SCE&G expects that it has or can obtain adequate sources of financing to
meet its projected cash requirements for the next 12 months and for the
foreseeable future. SCE&G's ratio of earnings to fixed charges for the 12 months
ended September 30, 2003 was 3.29.
CAPITAL TRANSACTIONS
On January 23, 2003 SCE&GFebruary 11, 2004 GENCO issued $200$100 million of First Mortgage Bonds
having an annualsenior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.80% and maturing January 15, 2033. The
proceeds5.49%. Proceeds from the sale of these bondsthis issuance were used to reduce short-term debt and
for general corporate purposes.
On May 21, 2003 SCE&G issued $300 million First Mortgage Bonds having an
annual interest rate of 5.30% and maturing on May 15, 2033. SCE&G used the net
proceeds from the sale of these bonds and certain other SCE&G funds to redeem
its $100 million principal amount of 7.625% First Mortgage Bonds due June 15,
2023, its $150 million principal amount of 7.50% First Mortgage Bonds due June
1, 2023 and its Junior Subordinated Debentures which effected the redemption of
$50 million aggregate amount of 7.55% Trust Preferred Securities, Series A,
issued by SCE&G Trust I.
On November 6, 2003 SCE&G issued $250 million First Mortgage Bonds
having an annual interest rate of 5.25% and maturing on November 1, 2018. SCE&G
will use the net proceeds from the sale of these bonds for the payment at
maturity of SCE&G's $100 million principal amount of 6.25% First Mortgage Bonds
due December 15, 2003, for repayment of short-term debt primarily incurred as a
result of SCE&G'ssupport GENCO's construction program and to repay intercompany advances borrowed for general corporate purposes.
that purpose.
CAPITAL PROJECTS
In May 2002
Construction of SCE&G began construction of an&G's 875 megawatt generation facility in Jasper County, South Carolina to supply electricity to its South
Carolina customers.has been completed. The facility will includeincludes three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility is expected to beginbegan commercial operation in mid-2004, and SCG
Pipeline, Inc., an affiliate, will transport natural gas to the facility. Costs
incurred through September 30, 2003 totaled approximately $421 million.May 2004.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray damDam in order to comply with new federal safety standards and maintain the lake in
case of an extreme earthquake.standards. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through September 30, 2003March 31, 2004 totaled approximately $126$192 million.
In 2002 SCE&G entered into 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 above 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, 2003 SCE&G had not
yet borrowed under the agreement.
ENVIRONMENTAL MATTERS
For information on environmental matters see Note 5C of Notes To
Condensed Consolidated Financial Statements.
to condensed consolidated financial statements.
OTHER MATTERS
Nuclear Station License Extension
In August 2002 SCE&G filed an application withApril 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). If approved, theThe extension would allowallows the plant to operate through 2042. At September 30, 2003 SCE&G had capitalized in
construction work in progress approximately $7 million related to the
application process and expects to capitalize an additional $2 million. SCE&G
expects the extension to be granted in mid-2004.
Synthetic Fuel
SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of September 30, 2003March 31, 2004 is approximately $3 million, and through September 30, 2003,March 31, 2004, they have generated and passed through to SCE&G approximately $83$107 million in such tax credits. At September 30, 2003March 31, 2004 SCE&G has recorded $59on its balance sheet $74 million ofnet deferred fuel tax benefits, which include partnership losses, net of tax.
Under a plan approved by the SCPSC, any tax credits generated 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 will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1A of Notes1B to Consolidated
Financial Statements.
On June 27, 2003condensed consolidated financial statements.
In March 2004 SCANA received a "No Change" letter from the Internal Revenue Service (IRS) announced that it
is reviewing the scientific validity of certain test procedures and results that
have been presented as evidence that solid coal-based synthetic fuels have
undergone a significant chemical change. Pending completion of this review, the
IRS suspended the issuance of Private Letter Rulings on the question of
significant chemical change for requests that rely on the testing procedures and
results being reviewed. Upon finishing this review, on October 29, 2003, the IRS
issued Announcement 2003-70, finishing its review, and confirming that the test
procedures and results used by taxpayers are scientifically valid if the
procedures are applied in a consistent and unbiased manner.related to SCE&G believes its
test procedures will meet the standards contemplated&G's interest in the Announcement.
Although one ofsynthetic fuel partnership S. C. Coaltech No. l L.P. for the partnerships in which SCE&G owns an interest is currently
under audit bytax year 2000. This letter supports SCANA's position that the IRS, there have been no issues raised with respect to the
validity of synthetic fuel tax credits. While SCE&G is not able to determine
what conclusion the IRS will reach in these matters, to the extent the IRS
disallows synfuel tax credits generated by either of the two partnerships, the
Company's and SCE&G's financial position, results of operations and cash flows
would not be materially adversely affected.
RESULTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003
AS COMPARED TO THE CORRESPONDING PERIODS IN 2002
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and GENCO described below are held for purposes other than trading.
Interest rate risk - risk—The table below provides information about long-term debt issued by SCE&G and GENCO 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.
As of March 31, 2004 | Expected Maturity Date | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars Liabilities | 2004 | 2005 | 2006 | 2007 | 2008 | There- after | Total | Fair Value | ||||||||
Long-Term Debt: | ||||||||||||||||
Fixed Rate ($) | 139.2 | 189.2 | 169.9 | 39.2 | 39.2 | 1,821.9 | 2,398.6 | 2,339.8 | ||||||||
Average Interest Rate (%) | 7.46 | 7.37 | 8.51 | 6.86 | 6.86 | 6.03 | 6.42 |
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.
In June 2002 SCE&G entered into a parts availability agreement with a
supplier whereby turbine and stator bar parts will be stored by SCE&G to be
available when needed. The parts will remain the property of the supplier until
such time as they are removed from storage by SCE&G and payment is made. SCE&G
bears the risk of loss or repair for any part damaged while in storage and will
pay an availability fee each quarter based on the daily available parts stored.
In addition, SCE&G is obligated to purchase all remaining stored parts at the
termination dates of the contract, June 2009 for the turbine parts and December
2006 for the stator bar parts. As such, SCE&G has recorded a liability in Other
Long-Term Debt with an offsetting asset in Deferred Debits. At September 30,
2003 SCE&G had recorded $30.8 million for the turbine parts and $3.2 million for
the stator bar parts.
Item 4. Controls and Procedures
As of September 30, 2003March 31, 2004 an evaluation was performed under the supervision and with the participation of SCE&G's management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that as of September 30, 2003March 31, 2004 SCE&G's disclosure controls and procedures were effective. There has been no change in SCE&G's internal control over financial reporting during the quarter ended September 30, 2003March 31, 2004 that has materially affected or is reasonably likely to materially affect SCE&G's internal control over financial reporting.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
FINANCIAL SECTION
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).
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- -------------------------------------------------------- ---------------- -------------------
September 30, December 31,
Millions of dollars 2003 2002
- -------------------------------------------------------- ---------------- -------------------
Assets
Gas Utility Plant $932 $895
Accumulated depreciation (344) (318)
Acquisition adjustment, net of accumulated amortization 210 210
- -------------------------------------------------------- ---------------- -------------------
Gas Utility Plant, Net 798 787
- -------------------------------------------------------- ---------------- -------------------
Nonutility Property and Investments, Net 27 28
- -------------------------------------------------------- ---------------- -------------------
Current Assets:
Cash and temporary investments 5 1
Restricted cash and temporary investments 7 7
Receivables, net of allowance for uncollectible
accounts of $1 and $2 38 98
Receivables-affiliated companies 13 14
Inventories (at average cost):
Stored gas 62 38
Materials and supplies 5 6
Prepayments 8 1
Deferred income taxes, net 3 3
- -------------------------------------------------------- ---------------- -------------------
Total Current Assets 141 168
- -------------------------------------------------------- ---------------- -------------------
Deferred Debits:
Due from affiliate-pension asset 14 14
Regulatory assets 30 20
Other 5 7
- -------------------------------------------------------- ---------------- -------------------
Total Deferred Debits 49 41
- -------------------------------------------------------- ---------------- -------------------
Total $1,015 $1,024
======================================================== ================ ===================
======================================================== ================ ===================
Capitalization and Liabilities
Capitalization:
Common equity $493 $487
Long-term debt, net 283 286
- -------------------------------------------------------- ---------------- -------------------
Total Capitalization 776 773
- -------------------------------------------------------- ---------------- -------------------
Current Liabilities:
Short-term borrowings 35 31
Current portion of long-term debt 8 8
Accounts payable 27 44
Accounts payable-affiliated companies 4 7
Customer prepayments and deposits 10 12
Taxes accrued 5 5
Interest accrued 4 6
Distributions/dividends declared 4 5
Other 10 11
- -------------------------------------------------------- ---------------- -------------------
Total Current Liabilities 107 129
- -------------------------------------------------------- ---------------- -------------------
Deferred Credits:
Deferred income taxes, net 96 91
Deferred investment tax credits 2 2
Due to affiliate-postretirement benefits 17 16
Regulatory liabilities 6 1
Other 11 12
- -------------------------------------------------------- ---------------- -------------------
Total Deferred Credits 132 122
- -------------------------------------------------------- ---------------- -------------------
Total $1,015 $1,024
======================================================== ================ ===================
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- --------------------------------------------------------------------------------------- --------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
Millions of dollars 2003 2002 2003 2002
- --------------------------------------------------------------------------- ----------- ------------ -------------
Operating Revenues $59 $39 $344 $222
Cost of Gas 37 18 221 107
- --------------------------------------------------------------------------- ----------- ------------ -------------
Gross Margin 22 21 123 115
- --------------------------------------------------------------------------- ----------- ------------ -------------
Operating Expenses:
Operation and maintenance 19 16 57 50
Depreciation 9 9 26 26
Other taxes 2 2 5 5
- --------------------------------------------------------------------------- ----------- ------------ -------------
Total Operating Expenses 30 27 88 81
- --------------------------------------------------------------------------- ----------- ------------ -------------
Operating Income (Loss) (8) (6) 35 34
Other Income, Including Allowance for Equity Funds
Used During Construction 2 1 6 3
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction 5 5 16 17
- --------------------------------------------------------------------------- ----------- ------------ -------------
Income (Loss) Before Income Tax Expense (Benefit)
and Cumulative
Effect of Accounting Change (11) (10) 25 20
Income Tax Expense (Benefit) (4) (4) 9 7
- --------------------------------------------------------------------------- ----------- ------------ -------------
- --------------------------------------------------------------------------- ----------- ------------ -------------
Income (Loss) Before Cumulative Effect of Accounting Change (7) (6) 16 13
Cumulative Effect of Accounting Change, net of taxes - - - (230)
- --------------------------------------------------------------------------- ----------- ------------ -------------
- --------------------------------------------------------------------------- ----------- ------------ -------------
Net Income (Loss) $(7) $(6) $16 $(217)
=========================================================================== =========== ============ =============
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- ------------------------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2003 2002
- ---------------------------------------------------------------------------- -------------
Cash Flows From Operating Activities:
Net income (loss) $16 $(217)
Adjustments to reconcile net income to net cash
provided from operating activities:
Cumulative effect of accounting change, net of taxes - 230
Depreciation 28 28
Allowance for funds used during construction (1) (1)
Over (under) collection, gas cost adjustment clause (5) (26)
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 61 43
(Increase) decrease in inventories (23) 4
(Increase) decrease in regulatory assets - 1
Increase (decrease) in accounts payable and advances (20) (29)
Increase (decrease) in deferred income taxes, net 5 (2)
Increase (decrease) in taxes accrued - (1)
Changes in other assets (5)
(1)
Changes in other liabilities 4 -
- ---------------------------------------------------------------------------- -------------
Net Cash Provided From Operating Activities 60 29
- ---------------------------------------------------------------------------- -------------
Cash Flows From Investing Activities:
Construction expenditures (36) (34)
Nonutility and other (1) (1)
- ------------------------------------------------------------------------- -------------
Net Cash Used For Investing Activities (37) (35)
- ------------------------------------------------------------------------- -------------
Cash Flows From Financing Activities:
Repayment of short-term borrowings, net (4) -
Capital contributions from parent 3 1
Retirement of long-term debt (3) -
Distributions/dividend payments (15) (9)
- ------------------------------------------------------------------------- -------------
Net Cash Used For Financing Activities (19) (8)
- ------------------------------------------------------------------------- -------------
Net Increase (Decrease) In Cash and Temporary Investments 4 (14)
Cash and Temporary Investments, January 1 1 18
- ------------------------------------------------------------------------- -------------
Cash and Temporary Investments, September 30 $5 $4
========================================================================= =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest
of $0.8 and $0.7) $16 $16
- Income taxes 14 13
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||||
---|---|---|---|---|---|---|---|---|---|
Assets | |||||||||
Gas Utility Plant | $ | 931 | $ | 923 | |||||
Accumulated depreciation | (261 | ) | (256 | ) | |||||
Acquisition Adjustment, Net of Accumulated Amortization | 210 | 210 | |||||||
Gas Utility Plant, Net | 880 | 877 | |||||||
Nonutility Property and Investments, Net | 27 | 28 | |||||||
Current Assets: | |||||||||
Cash and temporary investments | 33 | 18 | |||||||
Restricted cash and temporary investments | 8 | 7 | |||||||
Receivables, net of allowance for uncollectible accounts of $3 and $3 | 96 | 115 | |||||||
Receivables-affiliated companies | 6 | 5 | |||||||
Inventories (at average cost): | |||||||||
Stored gas | 26 | 56 | |||||||
Materials and supplies | 5 | 5 | |||||||
Prepayments | 1 | 2 | |||||||
Deferred income taxes, net | 4 | 3 | |||||||
Total Current Assets | 179 | 211 | |||||||
Deferred Debits: | |||||||||
Due from affiliate-pension asset | 13 | 13 | |||||||
Regulatory assets | 19 | 17 | |||||||
Other | 8 | 6 | |||||||
Total Deferred Debits | 40 | 36 | |||||||
Total | $ | 1,126 | $ | 1,152 | |||||
Capitalization and Liabilities | |||||||||
Capitalization: | |||||||||
Common equity | $ | 521 | $ | 502 | |||||
Long-term debt, net | 278 | 278 | |||||||
Total Capitalization | 799 | 780 | |||||||
Current Liabilities: | |||||||||
Short-term borrowings | — | 55 | |||||||
Current portion of long-term debt | 8 | 8 | |||||||
Accounts payable | 35 | 48 | |||||||
Accounts payable-affiliated companies | 5 | 2 | |||||||
Customer deposits | 7 | 7 | |||||||
Taxes accrued | 25 | 10 | |||||||
Interest accrued | 4 | 6 | |||||||
Distributions/dividends declared | 4 | 4 | |||||||
Other | 12 | 15 | |||||||
Total Current Liabilities | 100 | 155 | |||||||
Deferred Credits: | |||||||||
Deferred income taxes, net | 96 | 96 | |||||||
Deferred investment tax credits | 2 | 2 | |||||||
Due to affiliate-postretirement benefits | 17 | 17 | |||||||
Regulatory liabilities | 99 | 86 | |||||||
Other | 13 | 16 | |||||||
Total Deferred Credits | 227 | 217 | |||||||
Total | $ | 1,126 | $ | 1,152 | |||||
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
| Three Months Ended March 31, | ||||||
---|---|---|---|---|---|---|---|
Millions of dollars | |||||||
2004 | 2003 | ||||||
Operating Revenues | $ | 226 | $ | 203 | |||
Cost of Gas | 153 | 131 | |||||
Gross Margin | 73 | 72 | |||||
Operating Expenses: | |||||||
Operation and maintenance | 20 | 19 | |||||
Depreciation | 9 | 9 | |||||
Other taxes | 2 | 2 | |||||
Total Operating Expenses | 31 | 30 | |||||
Operating Income | 42 | 42 | |||||
Other Income, Including Allowance for Equity Funds Used During Construction | — | 2 | |||||
Interest Charges, Net of Allowance for Borrowed Funds Used During Construction | 5 | 5 | |||||
Income Before Income Tax Expense | 37 | 39 | |||||
Income Tax Expense | 14 | 15 | |||||
Net Income | $ | 23 | $ | 24 | |||
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| Three Months Ended March 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
Millions of dollars | ||||||||||
2004 | 2003 | |||||||||
Cash Flows From Operating Activities: | ||||||||||
Net income | $ | 23 | $ | 24 | ||||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||||
Depreciation and amortization | 9 | 9 | ||||||||
Loss on sale of assets | 1 | — | ||||||||
Over (under) collection, gas cost adjustment clause | 7 | (6 | ) | |||||||
Changes in certain assets and liabilities: | ||||||||||
(Increase) decrease in receivables, net | 18 | (6 | ) | |||||||
(Increase) decrease in inventories | 30 | 20 | ||||||||
Increase (decrease) in accounts payable | (10 | ) | 1 | |||||||
Increase (decrease) in deferred income taxes, net | (1 | ) | 1 | |||||||
Increase (decrease) in regulatory liabilities | 1 | — | ||||||||
Increase (decrease) in taxes accrued | 15 | 15 | ||||||||
Changes in other assets | — | 2 | ||||||||
Changes in other liabilities | (6 | ) | (8 | ) | ||||||
Net Cash Provided From Operating Activities | 87 | 52 | ||||||||
Cash Flows From Investing Activities: | ||||||||||
Construction expenditures | (13 | ) | (10 | ) | ||||||
Nonutility and other | — | (1 | ) | |||||||
Net Cash Used For Investing Activities | (13 | ) | (11 | ) | ||||||
Cash Flows From Financing Activities: | ||||||||||
Repayment of short-term borrowings, net | (55 | ) | (31 | ) | ||||||
Distributions/dividend payments | (4 | ) | (5 | ) | ||||||
Net Cash Used For Financing Activities | (59 | ) | (36 | ) | ||||||
Net Increase In Cash and Temporary Investments | 15 | 5 | ||||||||
Cash and Temporary Investments, January 1 | 18 | 1 | ||||||||
Cash and Temporary Investments, March 31 | $ | 33 | $ | 6 | ||||||
Supplemental Cash Flow Information: | ||||||||||
Cash paid for—Interest (net of capitalized interest of $0.2 and $0.4) | $ | 7 | $ | 6 | ||||||
—Income taxes | — | — |
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2003
March 31, 2004
(Unaudited)
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 (the Company) Annual Report on Form 10-K for the year ended December 31, 2002.2003. These are interim financial statements, and due to the seasonality of the Company's business, the amounts reported in the Condensed Consolidated Statements of OperationsIncome 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
A. Basis of Accounting
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 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, the Company has recorded as of September 30, 2003March 31, 2004 approximately $30$19 million and $6$99 million of regulatory assets and liabilities, respectively, as shown below.
September 30, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Excess deferred income taxes $- $(1)
Under-collections-gas cost adjustment clause, net 15 11
Deferred environmental remediation costs 9 9
- --------------------------------------------------------------------------------
Total $24 $19
================================================================================respectively. Information relating to regulatory assets and liabilities follows.
Millions of dollars | March 31, 2004 | December 31, 2003 | |||||
---|---|---|---|---|---|---|---|
Excess deferred income taxes | $ | (2 | ) | — | |||
Over-collections-gas cost adjustment clause, net | (8 | ) | $ | (1 | ) | ||
Deferred environmental remediation costs | 9 | 9 | |||||
Non-legal asset retirement obligations | (79 | ) | (77 | ) | |||
Total | $ | (80 | ) | $ | (69 | ) | |
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-collections-gas
Over-collections-gas cost adjustment clause, net represents amounts under-collectedover-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 clean-up 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 $2.4 million in costs have been incurred and deferred for subsequent rate consideration. (See Note 4.) Management believes that all MGP cleanup costs will be recoverable through gas rates. A portion
Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the costs incurred are being
recovered through rates, and management believes the remaining costsfuture retirement of approximately $7.5 million will be recoverable. Amounts incurred and deferred to
date that are not currently being recovered through gas rates are approximately
$1.5 million. (See Note 5.)assets for which no legal retirement obligation exists.
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.
B. New Accounting Standards
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets,"
effective January 1, 2002. In connection with this implementation, the Company
performed a valuation analysis of its acquisition adjustment using an
independent appraisal. The analysis indicated that the carrying amount of the
acquisition adjustment exceeded its fair value by approximately $230 million.
The resulting impairment charge is reflected on the Condensed Consolidated
Statement of Operations as the cumulative effect of an accounting change. SFAS
142 requires that an impairment evaluation be performed annually and at the same
time each year. The Company performed its annual evaluation as of January 1,
2003 and no further impairment was indicated.
The Company adopted SFAS 143, "Accounting for Asset Retirement
Obligations," effective January 1, 2003. SFAS 143 applies to legal obligations
associated with the retirement of tangible long-lived assets (ARO) and requires
the Company to recognize, as a liability, the fair value of an ARO in the period
in which it is incurred and to accrete the liability to its present value in
future periods. The Company believes that any ARO related to the Company's
property would be insignificant and, due to the indeterminate life of the
related assets, an ARO could not be reasonably estimated.
The Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. The provisions of SFAS 145, among other things,
discontinue treatment of gains or losses from the early extinguishment of debt
as extraordinary items unless such early extinguishment meets the criteria of
Accounting Principles Board Opinion (APB) 30. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.
The Company adopted SFAS 146 "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. This statement requires
companies to recognize costs associated with exit or disposal activities when
they are incurred rather than at the date of a commitment to an exit or disposal
plan. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities."
SFAS 149 is effective for contracts entered into or modified after June 30, 2003
and for hedging relationships designated after June 30, 2003. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of SFAS 149.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope
as a liability (or an asset in some circumstances). SFAS 150 was effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
was effective at the beginning of the first interim period beginning after June
15, 2003. There was no impact on the Company's results of operations, cash flows
or financial position from the initial adoption of SFAS 150.
C. Total Comprehensive Income
Total comprehensive income (loss) was not significantly different from net income (loss) for any period reported. Accumulated other comprehensive income (loss) of the Company totaled $(1.1) million and $(1.3)$(1.0) million as of September 30, 2003March 31, 2004 and December 31, 2002,2003, respectively.
D.
C. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003.
2004.
2. ACCOUNTING CHANGE
As a result of the January 1, 2002 adoption of SFAS 142, the Company
recorded a $230 million impairment charge related to the acquisition adjustment
which had been recorded in connection with its acquisition by SCANA Corporation.
The charge is reflected on the Condensed Consolidated Statements of Operations
as the cumulative effect of an accounting change. See additional information at
Note 1B.
3. 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, 20022003 through September 30, 2003March 31, 2004 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002
$.595
Rate Per Therm | Effective Date | ||
---|---|---|---|
$ | .460 | January–February 2003 | |
.595 | March 2003 | ||
.725 | April–November 2003 | ||
.600 | December 2003–March 2004 |
For service rendered on and after March 2003 $.215 February-June 2002
$.725 April-September 2003 $.350 July-October 2002
$.410 November-December 2002
On October 13, 2003 in connection with the Company's 2003 Annual
Prudence Review,1, 2004, the NCUC determined thatauthorized the Company's gas costs, including all
hedging transactions, were reasonableCompany to implement decrements in its sales and prudently incurred during the 12-month
review period ended March 31, 2003. The NCUC also authorized newtransportation rate decrementsschedules to refund overcollectionsreflect a decrease of certain gas costs includedapproximately $5.7 million in the Company's deferred accounts, effective November 1, 2003.annual fixed gas costs as well as the current over-recovery 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 would 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 Company estimates that the cost of this project will be approximately $31.4$31 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion is expected to bewas completed and placed in the spring ofservice in April 2004. Through September 30,
2003March 31, 2004 approximately $24.4$29 million had been spent on this project.
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 cases until
August 2005. General rate relief can be obtained during this period to recover costs associated with material adverse governmental actions and force majeure events.
4.
3. FINANCIAL INSTRUMENTS
The Company follows the guidance required by SFAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended, requires thein accounting for derivatives, including those arising from cash flow hedges related to natural gas.
The Company to recognize all derivative
instruments as either assets or liabilities in the statement of financial
position and to measure those instruments at fair value. SFAS 133 further
provides that changes in the fair value of derivative instruments are either
recognized in earnings or reported as a component of other comprehensive income,
depending upon the intended use of the derivative and the resulting designation.
The fair value of the derivative instruments is determined by reference to
quoted market prices of listed contracts, published quotations or quotations
from independent parties.
In January 2003 the Company filed a summary of itsutilizes hedging programactivities for natural gas purchases with the NCUC for informational purposes. The primary goal
of the program is to reduce price volatility to firm customers. In an October
2003 order, the NCUC declared the program was reasonable.purchases. Transaction fees and any realized gains or losses are recorded in deferred accounts for subsequent rate consideration. As of September 30, 2003March 31, 2004 the Company had deferred a net gaincosts of approximately $0.6$1.9 million.
The Company uses interest ratealso utilizes swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable rate and
receive fixed rate interest payments and are designated as fair value hedges of
certain debt instruments. The Company may terminate a swap agreement and may
replace it with a new swap also designated as a fair value hedge.
The fair value of interest rate swaps is recorded within other deferred
debits on the balance sheet. The resulting credits serve to reflect the hedged
long-term debt at its fair value. Periodic receipts or payments related to the
interest rate swaps are credited or charged to interest expense as incurred.
At September 30, 2003March 31, 2004 the estimated fair value of the Company's swaps totaled $2.9$2.7 million related to combined notional amounts of $37.4$33.1 million.
5.
4. COMMITMENTS AND CONTINGENCIES
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 $7.5approximately $6.8 million, which reflects the estimated remaining liability at September 30, 2003.March 31, 2004. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $1.5$2.4 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.
6.
5. SEGMENT OF BUSINESS INFORMATION
Gas Distribution is the Company's only reportable segment. Gas Distribution uses operating income to measure profitability. Intersegment revenues between Gas Distribution and nonreportable segments were not significant.
Disclosure of Reportable Segments
(Millions
(Millions of dollars)
Three Months Ended
September 30, 2003 2002
-------------------------------------------------- ---------------------------
-------------------------------------------------- ------------- -------------
External Operating External Operating
Revenue Loss Revenue Loss
-------------------------------------------------- ------------- -------------
Gas Distribution $59 $(8) $39 $(6)
All Other - n/a - n/a
-------------------------------------------------- ------------- -------------
Consolidated Total $59 $(8) $39 $(6)
================================================== ============= =============
Nine Months Ended
September 30, 2003 2002
----------------------------------------------------------- ------------- -------------- -------------
----------------------------------------------------------- ------------- -------------- -------------
External Operating Segment External Operating Segment
Revenue Income Assets Revenue Income Assets
----------------------------------------------------------- ------------- -------------- -------------
Gas Distribution $344 $35 $997 $222 $34 $1,155
All Other - n/a 28 - n/a 29
Adjustments/Eliminations - - (10) - - 2
----------------------------------------------------------- ------------- -------------- -------------
Consolidated Total $344 $35 $1,015 $222 $34 $1,186
=========================================================== ============= ============== =============
| 2004 | 2003 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Three months Ended March 31, | |||||||||||||||||||
External Revenue | Operating Income | Segment Assets | External Revenue | Operating Income | Segment Assets | ||||||||||||||
Gas Distribution | $ | 226 | $ | 42 | $ | 1,039 | $ | 203 | $ | 42 | $ | 1,023 | |||||||
All Other | — | n/a | 28 | — | n/a | 28 | |||||||||||||
Adjustments/Eliminations | — | — | 59 | — | — | (18 | ) | ||||||||||||
Consolidated Total | $ | 226 | $ | 42 | $ | 1,126 | $ | 203 | $ | 42 | $ | 1,033 | |||||||
Item 2. Management's Narrative Analysis of Results of Operations.
---------------------------------------------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
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 (PSNC Energy) Annual Report on Form 10-K for the year ended December 31, 2002.2003.
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) changes in the utility regulatory environment, (3) changes in the economy, especially in PSNC Energy's service territory, (4) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (5) growth opportunities, (6) the results of financing efforts, (7) changes in PSNC Energy's accounting policies, (8) weather conditions, especially in areas served by PSNC Energy, (9) performance of SCANA Corporation's (SCANA) pension plan assets and the impact on PSNC Energy's results of operations, (10) inflation, (11) changes in environmental regulations and (12) 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 (Loss) and Distributions/Dividends
Net income (loss)decreased for the ninethree months ended September 30,March 31, 2004 approximately $1.6 million compared to the same period in 2003 and 2002
was as follows:
- -------------------------------------------------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2003 2002
- ------------------------------------------------------------------ ------------
Net income (loss) $15.9 $(216.5)
Less: Cumulative effect of accounting change - (229.6)
- ------------------------------------------------------------------ ------------
- ------------------------------------------------------------------ ------------
Income before cumulative effect of accounting change $15.9 $13.1
================================================================== ============
Income before cumulative effect of accounting change increased
approximately $2.8 million primarily due to increased margin of $8.1 million and
other income of $3.2 million which were partially offset by higher operating expenses of $6.4$1.7 million and higherlower other income of $1.5 million, partially offset by increased margin of $0.7 million and lower income taxes of $2.2$0.9 million.
In connection with the implementation of SFAS 142, PSNC Energy performed
a valuation analysis of its acquisition adjustment using an independent
appraisal. The analysis indicated that the carrying amount of the acquisition
adjustment exceeded its fair value by $230 million. As a result, PSNC Energy
recorded an impairment charge of $230 million effective January 1, 2002. The
charge is presented on the Condensed Consolidated Statements of Operations as
the Cumulative Effect of an Accounting Change. SFAS 142 requires that an
impairment evaluation be performed annually and at the same time each year. PSNC
Energy performed an annual evaluation as of January 1, 2003 and no further
impairment was indicated.
The nature of PSNC Energy's business is seasonal. The quarters ending 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.
PSNC Energy's Board of Directors has authorized the following distributions/dividends on common stock held by SCANA during 2003:
- --------------------- --------------- -------------------- -------------------
Declaration Date Amount Quarter Ended Payment Date
- --------------------- --------------- -------------------- -------------------
- --------------------- --------------- -------------------- -------------------
February 20, 2003 $4.5 million March 31, 2003 April 1, 2003
May 1, 2003 $4.5 million June 30, 2003 July 1, 2003
July 31, 2003 $4.0 million September 30, 2003 October 1, 2003
- --------------------- --------------- -------------------- -------------------
2004:
Declaration Date | Amount | Quarter Ended | Payment Date | |||
---|---|---|---|---|---|---|
February 19, 2004 | $4.0 million | March 31, 2004 | April 1, 2004 | |||
April 29, 2004 | $3.5 million | June 30, 2004 | July 1, 2004 |
Gas Distribution
Gas distribution is comprised of the local distribution operations of PSNC Energy. Changes in the gas distribution sales margins were as follows:
------------------------ -----------------------------------------
Nine Months Ended
September 30,
Millions of dollars 2003 2002 Change
------------------------ --------- --------- ---------------------
------------------------ ----------
Operating revenues $344.0 $222.0 $122.0 55.0%
Less: Cost of gas 220.6 106.7 113.9 106.8%
------------------------ --------- --------- ----------
Gross margin $123.4 $115.3 $8.1 7.0%
======================== ========= ========= ========== ==========
| First Quarter | |||||||
---|---|---|---|---|---|---|---|---|
Millions of dollars | 2004 | % Change | 2003 | |||||
Operating revenues | $ | 226.0 | 11.2 | % | $ | 203.2 | ||
Less: Cost of gas | 153.4 | 16.8 | % | 131.3 | ||||
Gross margin | $ | 72.6 | 1.0 | % | $ | 71.9 | ||
Gas distribution sales margin for the ninethree months ended September 30,
2003March 31, 2004 increased primarily due to weather that was 14% colder than in 2002 and
increased customer growth of approximately 2.7%. Revenues$1.9 million, higher other operating revenues of $0.3 million and a positive margin impact from changes in the benchmark cost of gas increased asof approximately $0.3 million. This increase was partially offset by a resultdecline in customer usage per degree day of higher commodity natural gas prices.
approximately $2.1 million.
Operation and Maintenance Expenses
Operation and maintenance expenses increased $6.4$1.7 million for the ninethree months ended September 30, 2003March 31, 2004 compared to the same period in 20022003 primarily due to increased bad debt expense of $2.4 million related to greater natural gas
throughput and increased cost of gas. Also contributing to the increase are
higher labor and benefits costs of $1.6$0.9 million and increased outside laboradministrative and general business expenses of $1.7 million and the impact of reduced pension
income of $0.7 million.
Other Income
Other income increased $3.2decreased $1.5 million compared to the same period in 20022003 primarily due to increased incomea $1.0 million loss recognized on the sale of $1.1 million from secondary market
activities, such as off-system gas sales and pipeline capacity release, and
increased 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. In addition,
merchandising and jobbing income increased $1.4 million due to reduced interest
income of $0.8 millionEnergy's former corporate headquarters in 2002 and a reduced provision for bad debt of $0.6
million.
Gastonia, North Carolina.
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 20032004 construction budget is approximately $46.7$51 million, compared to actual construction expenditures for 2002through March 31, 2004 of $47.8$13.4 million. PSNC Energy's ratio of earnings to fixed charges for the 12 months ended September 30, 2003March 31, 2004 was 2.96.3.27.
At September 30, 2003March 31, 2004 PSNC Energy had $35.4 million inno outstanding short-term borrowings and had unused lines of credit of $89.6$125 million.
Item 4. Controls and Procedures
As of September 30, 2003March 31, 2004 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, 2003March 31, 2004 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, 2003March 31, 2004 that has materially affected or is reasonably likely to materially affect PSNC Energy's internal control over financial reporting.
Item 1. Legal Proceedings
The following legal proceedings were pending at September 30, 2003.
These proceedings affect SCANA Corporation and its subsidiaries (the Company)
and, to the extent indicated, they also affect SCE&G or PSNC Energy.
Rate and Other Regulatory Matters
In May 2002 the SCPSC issued an order approving SCE&G's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflected higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for under-collected actual fuel costs through April 2001,
including short-term purchased power costs necessitated by outages at two of
SCE&G's base load generating plants in winter 2000-2001. The new rates were
effective as of the first billing cycle in May 2002. The Consumer Advocate of
South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the
portion of the SCPSC's order related to the recovery of certain purchased power
costs. The appeal is still pending.
In April 2003 the SCPSC issued an order approving SCE&G's request to
maintain the fuel cost component of rates at 1.678 cents per KWh, effective May
1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices
and recognized the efficiency of SCE&G's electric generating plants; however, it
deferred action on the recovery of certain purchased power costs pending the
appeal to the Circuit Court of the SCPSC's May 2002 order.
On October 13, 2003 in connection with PSNC Energy's 2003 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, 2003. The NCUC also authorized new rate decrements
to refund overcollections of certain gas costs included in PSNC Energy's
deferred accounts, effective November 1, 2003.
On October 28, 2003, as part of the annual review of gas costs, the
SCPSC approved SCE&G's request to decrease the cost of gas component from $.928
per therm to $.867 per therm effective with the first billing cycle in November
2003.
The SCPSC allows SCE&G to recover through a billing surcharge to its
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 the billing surcharge from
3.0 cents per therm to 2.2 cents per therm, which is intended to provide for the
recovery, prior to the end of the year 2009, of the balance remaining at
September 30, 2003 of $11.6 million
Lake Murray Dam Reinforcement
In October 1999 the United States Federal Energy Regulatory Commission
(FERC) mandated that SCE&G reinforce its Lake Murray dam in order to comply with
new federal safety standards and maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001 is expected to cost approximately $275 million and be
completed in 2005. Costs incurred through September 30, 2003 totaled
approximately $126 million.
Environmental
SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. SCE&G
anticipates that the remaining remediation activities will be completed by the
end of 2004, with certain monitoring and retreatment activities continuing until
2007. As of September 30, 2003, SCE&G has spent approximately $19.6 million to
remediate the Calhoun Park site. Total remediation costs are estimated to be
$21.9 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. Two of these sites are currently being
remediated under work plans approved by DHEC. SCE&G is continuing to investigate
the remaining site and is monitoring the nature and extent of residual
contamination. In addition, in March 2003 SCE&G signed a consent agreement with
DHEC related to a site formerly owned by SCE&G. The site contained residue
material that was moved from an MGP site. The removal action for this site has
been completed. SCE&G anticipates that major remediation activities for the
three owned sites will be completed before 2006. As of September 30, 2003, SCE&G
has spent approximately $3.9 million related to these three sites, and expects
to spend an additional $5.2 million. Total remediation costs are estimated to be
$9.1 million.
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 $7.5
million, which reflects the estimated remaining liability at September 30, 2003.
Amounts incurred and deferred to date that are not currently being recovered
through gas rates are approximately $1.5 million. Management believes that all
MGP cleanup costs incurred by PSNC Energy will be recoverable through gas rates.
Pending or Threatened Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of
a subsidiary of the Company filed suit against SCANA Corporation in South
Carolina 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. The Company is confident in its
position and intends to vigorously defend the lawsuit. The Company does not
believe that the resolution of this issue will have a material adverse impact on
its results of operations, cash flows or financial position.
In 2001 a subsidiary of the Company entered into, in the ordinary course
of business, a 15-year take-and-pay contract with an unaffiliated natural gas
supplier to purchase 190,000 DT of natural gas per day beginning in the spring
of 2004. In December 2002, as a result of the failure of the supplier and its
guarantor to meet contractual obligations related to credit support provisions,
the subsidiary terminated the contract and the supplier initiated arbitration. A
hearing under the binding arbitration provisions of the contract was postponed
from September 2003 until at least January 2004 after the parties made progress
towards a settlement. In initial pleadings for the hearing, the supplier
demanded payment of at least $134 million in damages from the subsidiary;
conversely, the subsidiary demanded payment of no less than $154 million in
damages from the supplier. The Company is confident of the propriety of its
actions and will vigorously pursue its position if the arbitration hearing is
held. 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.
An action was filed on October 22, 2003 against SCE&G by the State of
South Carolina. The Complaint alleges SCE&G violates the Unfair Trade Practices
Act by charging municipal franchise fees to some customers residing outside a
municipality's limits. The Complaint also alleges that SCE&G failed to obey,
observe, or comply with the lawful order of the SCPSC by charging franchise fees
to those not residing in a municipality. The Complaint seeks restitution to all
affected customers and penalties up to $5,000 for each separate violation. SCE&G
is confident of the reasonableness of its actions and intends to mount a
vigorous defense. The allegations contained in this Complaint are the subject of
a similar lawsuit that was filed and served on SCE&G and a Motion to Dismiss is
pending. The allegations are also the subject of a threatened class action
lawsuit. SCE&G further believes that the resolution of this action will not have
a material adverse impact on its results of operations, cash flows or financial
condition. 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 which the SCPSC deems just and
proper to regulate the franchise fee collection process.
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 South Carolina Electric & Gas Company, 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 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 line right-of-way constitutes a trespass. The Company is confident
of the propriety of its 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.
The Company, SCE&G and PSNC Energy are also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without material loss to the Company. The status of matters previously disclosed in the Company's Annual Report on Form 10-K for 2003 have not changed significantly.
Item 2,2. Purchases of Equity Securities by the Issuer and Affiliated Purchases
Period | (a) Total number of shares (or units) purchased | (b) Average price paid per share (or unit) | (c) Total number of shares (or units) purchased as part of publicly announced plans or programs | (d) Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs | |||||
---|---|---|---|---|---|---|---|---|---|
January 1, 2004– January 31, 2004 | — | — | — | 1,155,670 | |||||
February 1, 2004– February 29, 2004 | 55,000 | $ | 34.54 | 55,000 | 1,100,673 | ||||
March 1, 2004– March 31, 2004 | 60,400 | $ | 35.86 | 60,400 | 1,018,981 | ||||
Total | 115,400 | $ | 35.23 | 115,400 | 1,018,981 | ||||
On October 24, 2003, the Company announced that it would repurchase shares of SCANA stock on the open market. Total shares repurchased could not exceed the aggregate, measured at the time of any such purchase, of the number of shares theretofore issued pursuant to the exercise of options granted under the Long-Term Equity Compensation Plan (the Plan) plus the number of shares issuable upon the exercise of options exercisable under the Plan as of the date of such purchase or to become exercisable within 60 days of such date. No expiration date was stated, and the program under which such repurchases were made did not expire during the period covered by the above table. Effective April 29, 2004, the Company discontinued purchasing outstanding shares of common stock on the open market.
Item 3, 4 and 5 are not applicable.
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits
SCANA Corporation, South Carolina Electric & Gas Company and Public Service Company of North Carolina, Incorporated:
Exhibits filed with this Quarterly Report on Form 10-Q are listed in the following Exhibit Index. 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.
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 subsidiaries, 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.
B. Reports on Form 8-K during the thirdfirst quarter 20032004 were as follows:
SCANA Corporation:
Date of Report: July 25, 2003
Items reported: Items 7 and 9 (Item 12 disclosure)
South Carolina Electric & Gas Company:
Date of Report: July 25, 2003
Items reported: Items 7 and 9 (Item 12 disclosure)
Public Service Company of North Carolina, Incorporated:
Date of Report: July 25, 2003
Items reported: Items 7 and 9 (Item 12 disclosure)
SCANA Corporation: | ||
Date of report: | February 13, 2004 | |
Items reported: | Items 7 & 12 | |
South Carolina Electric & Gas Company: | ||
Date of report: | February 13, 2004 | |
Items reported: | Items 7 & 12 | |
Public Service Company of North Carolina, Incorporated: | ||
Date of report: | February 13, 2004 | |
Items reported: | Items 7 & 12 |
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 thereunto duly authorized.
SCANA CORPORATION
SOUTH CAROLINA ELECTRIC & GAS COMPANY
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
(Registrants)
November 6, 2003 By: s/James E. Swan, IV
--------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED (Registrants) | |||
May 5, 2004 | By: | /s/ JAMES E. SWAN, IV James E. Swan, IV Controller (Principal accounting officer) |
Applicable to Form 10-Q of | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Exhibit No. | SCANA | SCE&G | PSNC Energy | Description | ||||||||
3.01 | X | Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. | ||||||||||
3.02 | X | Articles of Amendment | ||||||||||
3.03 | X | Restated Articles of Incorporation of | ||||||||||
3.04 | X | Articles of Amendment | ||||||||||
May 22, 2001 | Exhibit 3.02 | to Registration No. 333-65460 | ||||||||||
June 14, 2001 | Exhibit 3.04 | to Registration No. 333-65460 | ||||||||||
August 30, 2001 | Exhibit 3.05 | to Registration No. 333-101449 | ||||||||||
March 13, 2002 | Exhibit 3.06 | to Registration No. 333-101449 | ||||||||||
May 9, 2002 | Exhibit 3.07 | to Registration No. 333-101449 | ||||||||||
June 4, 2002 | Exhibit 3.08 | to Registration No. 333-101449 | ||||||||||
August 12, 2002 | Exhibit 3.09 | to Registration No. 333-101449 | ||||||||||
March 13, 2003 | Exhibit 3.05 | to Registration No. 333-108760 | ||||||||||
May 22, 2003 | Exhibit 3.05 | to Registration No. 333-108760 | ||||||||||
June 18, 2003 | Exhibit 3.06 | to Registration No. 333-108760 | ||||||||||
August 7, 2003 | Exhibit 3.06 | to Registration No. 333-108760 | ||||||||||
3.05 | X | Articles of Correction | ||||||||||
3.06 | X | Articles of | ||||||||||
May 3, 2001 | Exhibit | |||||||||||
May 22, 2001 | Exhibit 3.07 | |||||||||||
June 14, 2001 | Exhibit 3.08 | |||||||||||
August 30, 2001 | Exhibit | |||||||||||
March 13, 2002 | Exhibit 3.10 | |||||||||||
May 9, 2002 | Exhibit 3.11 | |||||||||||
June 4, 2002 | Exhibit 3.12 | |||||||||||
August 12, 2002 | Exhibit 3.13 | |||||||||||
March 13, 2003 | Exhibit 3.14 | |||||||||||
May 22, 2003 | Exhibit 3.15 | |||||||||||
June 18, 2003 | Exhibit 3.16 | |||||||||||
August 7, 2003 | Exhibit 3.17 | |||||||||||
3.07 | X | By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit 3.01 to Registration Statement No. | ||||||||||
3.08 | X | By-Laws of SCE&G as | ||||||||||
3.09 | X | By-Laws of PSNC Energy as revised and amended on February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No. | ||||||||||
4.01 | X | X | Articles of Exchange of South Carolina Electric | |||||||||
4.02 | X | Indenture dated as of November 1, 1989 between SCANA Corporation and The Bank of New York, as Trustee (Filed as Exhibit 4-A to Registration | ||||||||||
4.03 | X | X | Indenture 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. | |||||||||
4.04 | X | X | Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4.03, pursuant to which SCE&G assumed said Indenture | |||||||||
4.05 | X | X | Fifth through Fifty-third Supplemental | |||||||||
December 1, 1950 | Exhibit 2-D | to Registration No. 2-26459 | ||||||||||
July 1, 1951 | Exhibit 2-E | to Registration No. 2-26459 | ||||||||||
June 1, 1953 | Exhibit 2-F | to Registration No. 2-26459 | ||||||||||
June 1, 1955 | Exhibit 2-G | to Registration No. 2-26459 | ||||||||||
November 1, 1957 | Exhibit 2-H | to Registration No. 2-26459 | ||||||||||
September 1, 1958 | Exhibit 2-I | to Registration No. 2-26459 | ||||||||||
September 1, 1960 | Exhibit 2-J | to Registration No. 2-26459 | ||||||||||
June 1, 1961 | Exhibit 2-K | to Registration No. 2-26459 | ||||||||||
December 1, 1965 | Exhibit 2-L | to Registration No. 2-26459 | ||||||||||
June 1, 1966 | Exhibit 2-M | to Registration No. 2-26459 | ||||||||||
June 1, 1967 | Exhibit 2-N | to Registration No. 2-29693 | ||||||||||
September 1, 1968 | Exhibit 4-O | to Registration No. 2-31569 | ||||||||||
June 1, 1969 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
December 1, 1969 | Exhibit 4-O | to Registration No. 2-35388 | ||||||||||
June 1, 1970 | Exhibit 4-R | to Registration No. 2-37363 | ||||||||||
March 1, 1971 | Exhibit 2-B-17 | to Registration No. 2-40324 | ||||||||||
January 1, 1972 | Exhibit 2-B | to Registration No. 33-38580 | ||||||||||
July 1, 1974 | Exhibit 2-A-19 | to Registration No. 2-51291 | ||||||||||
May 1, 1975 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
July 1, 1975 | Exhibit 2-B-21 | to Registration No. 2-53908 | ||||||||||
February 1, 1976 | Exhibit 2-B-22 | to Registration No. 2-55304 | ||||||||||
December 1, 1976 | Exhibit 2-B-23 | to Registration No. 2-57936 | ||||||||||
March 1, 1977 | Exhibit 2-B-24 | to Registration No. 2-58662 | ||||||||||
May 1, 1977 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
February 1, 1978 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
June 1, 1978 | Exhibit 2-A-3 | to Registration No. 2-61653 | ||||||||||
April 1, 1979 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
June 1, 1979 | Exhibit 2-A-3 | to Registration No. 33-38580 | ||||||||||
April 1, 1980 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
June 1, 1980 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
December 1, 1980 | Exhibit 4-C | to Registration No. 33-38580 | ||||||||||
April 1, 1981 | Exhibit 4-D | to Registration No. 33-38580 | ||||||||||
June 1, 1981 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
March 1, | Exhibit 4-D | to Registration No. 2-73321 | ||||||||||
April 15, 1982 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
May 1, 1982 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
December 1, | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
December 1, | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
June 1, | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
February 1, | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
September 1, 1987 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
January 1, 1989 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
January 1, 1991 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
July 15, 1991 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
August 15, 1991 | Exhibit 4-D | to Registration No. 33-49421 | ||||||||||
April 1, 1993 | Exhibit 4-E | to Registration No. 33-49421 | ||||||||||
July 1, 1993 | Exhibit 4-D | to Registration No. | ||||||||||
May 1, 1999 | Exhibit 4.04 | to Registration No. 333-86387 | ||||||||||
4.06 | X | X | Indenture 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. | |||||||||
4.07 | X | X | First 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. | |||||||||
4.08 | X | X | Second 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. | |||||||||
4.09 | X | X | Indenture dated as of January 1, 1996 between PSNC | |||||||||
4.10 | X | X | First through Fourth Supplemental | |||||||||
January 1, 1996 | Exhibit 4.09 | to Registration No. 333-45206 | ||||||||||
December 15, 1996 | Exhibit 4.10 | to Registration No. 333-45206 | ||||||||||
February 10, 2000 | Exhibit 4.11 | to Registration No. 333-45206 | ||||||||||
February 12, 2001 | Exhibit 4.05 | to Registration No. 333-68516 | ||||||||||
4.11 | X | X | PSNC | |||||||||
*10.01 | X | X | X | SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, | ||||||||
*10.02 | X | X | X | SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed as Exhibit 4.03 to Registration Statement No. | ||||||||
*10.03 | X | X | X | Amendment to SCANA | ||||||||
*10.04 | X | X | X | SCANA Supplementary Executive Retirement Plan as amended July 1, 2001 (Filed as Exhibit 10.02 to Form 10-Q for the quarter ended September 30, | ||||||||
*10.05 | X | X | X | SCANA 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, | ||||||||
*10.06 | X | X | X | SCANA Supplementary Key | ||||||||
*10.07 | X | X | X | SCANA Long-Term Equity Compensation Plan dated January 2000 | ||||||||
*10.08 | X | X | X | Amendment to SCANA Long-Term Equity Compensation Plan | ||||||||
*10.09 | X | X | X | Description 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. | ||||||||
*10.10 | X | X | X | Description 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. | ||||||||
10.11 | X | Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed as Exhibit 10.01 to Registration Statement No. | ||||||||||
10.12 | X | Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1, 1995 (Filed as Exhibit 10.02 to Registration Statement No. | ||||||||||
10.13 | X | Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19, 1996 (Filed as Exhibit 10.03 to Registration Statement No. | ||||||||||
10.14 | X | Amended 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. | ||||||||||
10.15 | X | Service Agreement between PSNC | ||||||||||
10.16 | X | Service Agreement between SCE&G and SCANA Services, Inc., effective | ||||||||||
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) | ||||||||||
32.03 | X | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | ||||||||||
32.04 | X | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | ||||||||||
32.05 | X | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | ||||||||||
32.06 | X | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) |