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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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
(803) 217-9000
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 X No South
Carolina Electric & Gas Company Yes X No Public Service Company of North
Carolina, Incorporated Yes X No
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). SCANA Corporation Yes X No South Carolina
Electric & Gas Company Yes No X Public Service Company of North Carolina,
Incorporated Yes No X
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 July 31,
---------- ------------ ------------
2003
SCANA Corporation Without Par Value 110,922,883
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)
(a)Held beneficially and of record by SCANA Corporation.
This combined Form 10-Q is separately filed by SCANA Corporation, South
Carolina Electric & Gas Company and Public Service Company of North Carolina,
Incorporated. Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no representation as
to information relating to the other companies.
Public Service Company of North Carolina, Incorporated meets the
conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and
therefore is filing this form with the reduced disclosure format allowed under
General Instruction H(2).
================================================================================
INDEX
Page
PART I. FINANCIAL INFORMATION
SCANA Corporation Financial Section.................................................................................... 3
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002 ......................... 4
Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2003 and 2002............. 6
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2003 and 2002............. 7
Condensed Consolidated Statements of Comprehensive Income (Loss) for the Periods
Ended June 30, 2003 and 2002........................................................................... 8
Notes to Condensed Consolidated Financial Statements..................................................... 9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................ 21
Item 3. Quantitative and Qualitative Disclosures About Market Risk................................................... 29
Item 4. Controls and Procedures...................................................................................... 31
South Carolina Electric & Gas Company Financial Section................................................................ 32
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002 ......................... 33
Condensed Consolidated Statements of Income for the Periods Ended June 30, 2003 and 2002................. 35
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2003 and 2002............. 36
Notes to Condensed Consolidated Financial Statements..................................................... 37
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations......................... 44
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................................... 50
Item 4. Controls and Procedures....................................................................................... 50
Public Service Company of North Carolina, Incorporated Financial Section............................................... 51
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002 ......................... 52
Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2003 and 2002............. 53
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2003 and 2002............. 54
Condensed Consolidated Statements of Comprehensive Income (Loss) for the Periods
Ended June 30, 2003 and 2002.......................................................................... 55
Notes to Condensed Consolidated Financial Statements...................................................... 56
Item 2. Management's Narrative Analysis of Results of Operations...................................................... 60
Item 4. Controls and Procedures....................................................................................... 62
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................................................................. 63
Item 4. Submission of Matters to a Vote of Security Holders........................................................... 64
Item 6. Exhibits and Reports on Form 8-K.............................................................................. 65
Signatures............................................................................................................. 66
Exhibit Index.......................................................................................................... 67
Certifications Required by Rule 13a-14 ................................................................................ 72
Certifications Pursuant to 18 U.S.C. Section 1350...................................................................... 78
SCANA CORPORATION
FINANCIAL SECTION
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
SCANA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
- ------------------------------------------------------------------------------- ------------------ ------------------
June 30, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------- ------------------ ------------------
Assets
Utility Plant:
Electric $5,361 $5,228
Gas 1,631 1,593
Other 197 184
- ------------------------------------------------------------------------------- ------------------ ------------------
Total 7,189 7,005
Accumulated depreciation and amortization (2,577) (2,476)
- ------------------------------------------------------------------------------- ------------------ ------------------
Total 4,612 4,529
Construction work in progress 914 677
Nuclear fuel, net of accumulated amortization 28 38
Acquisition adjustments, net of accumulated amortization 230 230
- ------------------------------------------------------------------------------- ------------------ ------------------
Utility Plant, Net 5,784 5,474
- ------------------------------------------------------------------------------- ------------------ ------------------
Nonutility Property, Net of Accumulated Depreciation 93 95
Investments 220 231
- ------------------------------------------------------------------------------- ------------------ ------------------
- ------------------------------------------------------------------------------- ------------------ ------------------
Nonutility Property and Investments, Net 313 326
- ------------------------------------------------------------------------------- ------------------ ------------------
- ------------------------------------------------------------------------------- ------------------ ------------------
Current Assets:
Cash and temporary investments 220 374
Receivables, net of allowance for uncollectible accounts of
$21 and $17 377 478
Receivables - affiliated companies 15 8
Inventories (at average cost):
Fuel 147 166
Materials and supplies 58 61
Emission allowances 9 10
Prepayments 44 40
Deferred income taxes, net 8 -
- ------------------------------------------------------------------------------- ------------------ ------------------
Total Current Assets 878 1,137
- ------------------------------------------------------------------------------- ------------------ ------------------
Deferred Debits:
Environmental 21 27
Nuclear plant decommissioning - 87
Assets held in trust, net-nuclear decommissioning 36 -
Pension asset, net 266 265
Other regulatory assets 331 292
Other 167 146
- ------------------------------------------------------------------------------- ------------------ ------------------
Total Deferred Debits 821 817
- ------------------------------------------------------------------------------- ------------------ ------------------
Total $7,796 $7,754
=============================================================================== ================== ==================
- ------------------------------------------------------------------------------------ ------------------- -----------------
June 30, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------------ ------------------- -----------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $2,258 $2,177
Preferred stock (Not subject to purchase or sinking funds) 106 106
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Stockholders' Investment 2,364 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 2,930 2,834
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Capitalization 5,303 5,176
- ------------------------------------------------------------------------------------ ------------------- -----------------
Current Liabilities:
Short-term borrowings 212 209
Current portion of long-term debt 403 413
Accounts payable 222 354
Accounts payable - affiliated companies 13 8
Customer deposits 39 39
Taxes accrued 88 78
Interest accrued 55 52
Dividends declared 41 39
Deferred income taxes, net - 4
Other 52 77
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Current Liabilities 1,125 1,273
- ------------------------------------------------------------------------------------ ------------------- -----------------
Deferred Credits:
Deferred income taxes, net 754 747
Deferred investment tax credits 115 118
Reserve for nuclear plant decommissioning - 87
Asset retirement obligation - nuclear plant 114 -
Postretirement benefits 136 131
Regulatory liabilities 137 114
Other 112 108
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total Deferred Credits 1,368 1,305
- ------------------------------------------------------------------------------------ ------------------- -----------------
Total $7,796 $7,754
==================================================================================== =================== =================
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
- -------------------------------------------------------------------- --------------------------- ---------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars, except per share amounts 2003 2002 2003 2002
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Operating Revenues:
Electric $356 $349 $692 $651
Gas - regulated 193 155 620 451
Gas - nonregulated 177 145 483 369
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Total Operating Revenues 726 649 1,795 1,471
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Operating Expenses:
Fuel used in electric generation 80 92 161 166
Purchased power 16 16 26 21
Gas purchased for resale 293 234 865 613
Other operation and maintenance 141 131 285 258
Depreciation and amortization 60 55 120 108
Other taxes 36 32 70 63
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Total Operating Expenses 626 560 1,527 1,229
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Operating Income 100 89 268 242
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Other Income:
Other income, including allowance for equity funds
used during construction of $5, $6, $9 and $13 17 20 33 37
Gain on sale of investments and assets 56 15 56 31
Impairment of investments (7) (11) (7) (255)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Total Other Income (Expense) 66 24 82 (187)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income Before Interest Charges, Income Taxes,
Preferred Stock Dividends and Cumulative Effect
of Accounting Change 166 113 350 55
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction of $2, $3, $5 and $7 51 51 102 102
Dividend Requirement of SCE&G - Obligated
Mandatorily Redeemable Preferred Securities 1 1 2 2
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income (Loss) Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 114 61 246 (49)
Income Tax Expense (Benefit) 38 19 84 (21)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income (Loss) Before Preferred Stock Dividends and
Cumulative Effect of Accounting Change 76 42 162 (28)
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 2 2 4 4
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Income (Loss) Before Cumulative Effect of Accounting Change 74 40 158 (32)
Cumulative Effect of Accounting Change, net of taxes - - - (230)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Net Income (Loss) $74 $40 $158 $(262)
==================================================================== =============== =========== ============ ==============
==================================================================== =============== =========== ============ ==============
Basic and Diluted Earnings (Loss) Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $.67 $.38 $1.42 $(.30)
Cumulative Effect of Accounting Change, Net of Taxes - - - (2.20)
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
- -------------------------------------------------------------------- --------------- ----------- ------------ --------------
Basic and Diluted Earnings (Loss) Per Share $.67 $.38 $1.42 $(2.50)
==================================================================== =============== =========== ============ ==============
==================================================================== =============== =========== ============ ==============
Weighted Average Shares Outstanding (millions) 110.8 104.7 110.8 104.7
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- --------------------------------------------------------------------------------------- ----------------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash Flows From Operating Activities:
Net income (loss) $158 $(262)
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 125 113
Amortization of nuclear fuel 12 7
Gain on sale of investments and assets (56) (31)
Hedging activities (3) 39
Impairment on investments 7 255
Allowance for funds used during construction (14) (20)
Over (under) collection, fuel adjustment clauses 21 (21)
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 94 44
(Increase) decrease in inventories 23 25
(Increase) decrease in prepayments (4) (10)
(Increase) decrease in pension asset (1) (13)
(Increase) decrease in other regulatory assets (17) (5)
Increase (decrease) in deferred income taxes, net (4) (136)
Increase (decrease) in regulatory liabilities 21 17
Increase (decrease) in postretirement benefits 5 5
Increase (decrease) in accounts payable (127) (38)
Increase (decrease) in taxes accrued 10 (43)
Increase (decrease) in interest accrued 3 11
Changes in other assets (4) 8
Changes in other liabilities (7) 13
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Cash Provided From Operating Activities 242 188
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (380) (269)
Proceeds from sale of investments and assets 65 336
Increase in nonutility property (4) (7)
Investments in affiliates (8) (20)
- --------------------------------------------------------------------------------------- ------------------ ---------------
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Cash Provided From (Used For) Investing Activities (327) 40
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 495 295
Issuance of notes and loans 2 397
Issuance of common stock upon exercise of stock options 2 -
Repayments:
Mortgage bonds (250) (104)
Notes and loans (171) (605)
SCE&G Trust I Preferred Securities (50) -
Payment of deferred financing costs (21) -
Dividends and distributions:
Common stock (75) (66)
Preferred stock (4) (4)
Short-term borrowings, net 3 48
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Cash Used For Financing Activities (69) (39)
- --------------------------------------------------------------------------------------- ------------------ ---------------
Net Increase (Decrease) In Cash and Temporary Investments (154) 189
Cash and Temporary Investments, January 1 374 192
- --------------------------------------------------------------------------------------- ------------------ ---------------
Cash and Temporary Investments, June 30 $220 $381
======================================================================================= ================== ===============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $5 and $7) $100 $89
- Income taxes 24 105
Noncash Investing and Financing Activities:
Unrealized gain (loss) on securities available for sale, net of tax - 29
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- ------------------------------------------------------------------------------------- -----------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2003 2002 2003 2002
- ------------------------------------------------------------------------- ----------- ---------- ------------
- ------------------------------------------------------------------------- ----------- ---------- ------------
Net Income (Loss) $74 $40 $158 $(262)
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on securities available for sale - (64) - 29
Unrealized gains (losses) on hedging activities - 3 (2) 27
- ------------------------------------------------------------------------- ----------- ---------- ------------
Total Comprehensive Income (Loss) (1) $74 $(21) $156 $(206)
========================================================================= =========== ========== ============
(1) Accumulated other comprehensive income (loss) of the Company totaled $(0.4)
million and $1.0 million as of June 30, 2003 and December 31, 2002,
respectively.
See Notes to Condensed Consolidated Financial Statements.
SCANA CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2003
(Unaudited)
The following notes should be read in conjunction with the Notes to
Consolidated Financial Statements appearing in SCANA Corporation's (the Company)
Annual Report on Form 10-K for the year ended December 31, 2002. These are
interim financial statements, and due to the seasonality of the Company's
business, the amounts reported in the Condensed Consolidated Statements of
Operations are not necessarily indicative of amounts expected for the year. In
the opinion of management, the information furnished herein reflects all
adjustments, all of a normal recurring nature, which are necessary for a fair
statement of the results for the interim periods reported.
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 revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result the Company has
recorded, as of June 30, 2003, approximately $352 million and $137 million of
regulatory assets and liabilities, respectively, as shown below.
June 30, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Accumulated deferred income taxes, net $95 $95
Under-collections - fuel adjustment clauses 39 61
Deferred environmental remediation costs 21 27
Asset retirement obligation - nuclear decommissioning 51 -
Deferred non-conventional fuel tax benefits, net (52) (40)
Storm damage reserve (34) (32)
Franchise agreements 64 65
Other 31 29
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total $215 $205
================================================================================
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 - fuel adjustment clauses represent amounts
under-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, and such
costs, totaling approximately $12 million, are expected to be fully recovered by
the end of 2005. A portion of the costs incurred at sites owned by Public
Service Company of North Carolina, Incorporated (PSNC Energy) is also being
recovered through rates, and management believes the remaining costs of
approximately $7.6 million will be recoverable in the future. Amounts incurred
to date that have not been recovered through gas rates at PSNC Energy are
approximately $1.3 million. (See Note 3.)
Asset retirement obligation - nuclear decommissioning represents the
regulatory asset associated with the legal obligation of decommissioning and
dismantling V. C. Summer Nuclear Station (Summer Station) as required in SFAS
143, "Accounting for Asset Retirement Obligations." (See Note 1B).
Deferred non-conventional fuel tax benefits represent the deferral of
partnership losses and other expenses, offset by the accumulated deferred income
tax credits associated with two SCE&G partnerships involved in converting coal
to alternate fuel. Under a plan approved by the SCPSC, any tax credits generated
from non-conventional fuel produced and consumed by SCE&G and ultimately passed
through to SCE&G, net of partnership losses and other expenses, have been and
will be deferred and will be 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 ten-year period. 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 the next 15 years.
The SCPSC and the NCUC 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. 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 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 in the period the write-off would
be recorded, but it is not expected that cash flows or financial position would
be materially adversely affected.
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 $2.20 loss 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 an 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 June 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
June 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 36 39 35
Within other regulatory assets 51 45 42
------------- ---------------- -------
------------- ---------------- -------
Total $114 $111 $105
============= ================ =======
============= ================ =======
Liabilities:
Asset retirement obligation -
nuclear plant decommissioning $114 $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.
In addition to the ARO for Summer Station, 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. SFAS 149 is not
expected to have a material impact on the Company's results of operations, cash
flows or financial position.
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"), 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" 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 June 30, 2003, options issued and
outstanding under the Plan totaled approximately 1.6 million.
All options were granted with exercise prices equal to the fair market
value of the Company's stock on the respective grant dates; therefore, no
compensation expense has been recognized in connection with such grants. If the
Company had determined 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 Six Months Ended
June 30, June 30,
2003 2002 2003 2002
---- ---- ---- ----
Net income (loss) - as reported (millions) $74 $40 $158 $(262)
Net income (loss) - pro forma (millions) $73 $40 $157 $(262)
Basic and diluted earnings (loss) per share - as reported $.67 $.38 $1.42 $(2.50)
Basic and diluted earnings (loss) per share - pro forma $.66 $.38 $1.41 $(2.50)
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
affiliated companies for these investments approximately $15.5 million and $8.5
million at June 30, 2003 and December 31, 2002, respectively. SCE&G had recorded
as payables to affiliated companies for these investments approximately $13.2
million and $8.0 million at June 30, 2003 and December 31, 2002, 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
which had been 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 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 reflects 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 January 2003, in conjunction with the approval of the above 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 above appeal to the Circuit
Court of the SCPSC's May 2002 order.
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,
2002 through June 30, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002
$.928 March-June 2003 $.728 November-December 2002
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 2002, as a result of the annual
review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm,
which is intended to provide for the recovery, prior to the end of the year
2005, of the balance remaining at June 30, 2003 of $12.3 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, 2002 through June 30, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002
$.595 March 2003 $.215 February-June 2002
$.725 April-June 2003 $.350 July-October 2002
$.410 November-December 2002
On April 24, 2003 the NCUC issued an order in PSNC Energy's 2002 Annual
Prudence Review. The NCUC determined that PSNC Energy's gas costs during the
12-month review period ended March 31, 2002 were reasonable and prudently
incurred. The NCUC also authorized new temporary rate decrements to refund
certain balances in deferred accounts.
On June 2, 2003 PSNC Energy filed testimony in the 2003 Annual Prudence
Review related to the 12 months ended March 31, 2003. The NCUC will hold a
hearing on August 12, 2003 to review PSNC Energy's filing.
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 million. The Madison County and Jackson
County portions of the project were completed in 2002, and the Swain County
portion is expected to be completed in the spring of 2004. Through June 30, 2003
approximately $20.0 million had been spent on this project.
In December 1999 the NCUC issued an order approving SCANA'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. 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.
5. 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 June 30, 2003
approximately $42.4 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.
6. 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.
Telecommunications Investments
At June 30, 2003 SCANA Communications Holdings, Inc. (SCH), a wholly owned,
indirect subsidiary of the Company, held investments 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 $8.3
ITC^DeltaCom 566.0 thousand shares of common stock 1.1
154.2 thousand shares series A 8% preferred stock,
convertible in 2005 into 2.7 million shares of
common stock 12.9
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
14.8 million shares series C preferred stock, convertible
into
14.8 million shares of common stock 27.8
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 interest 46.5
On May 9, 2003, the Company's investment in ITC Holding Company, Inc. was
sold. The transaction resulted in the receipt of net after-tax cash proceeds of
approximately $46 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 $37 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 have a market value of $1.7 million. The ITC^DeltaCom preferred shares
owned by SCH are classified as held to maturity due to their debt features, and
the market value is not readily determinable. Knology, Inc. (Knology) is a
broadband service provider of cable television, telephone and internet
services.In June 2003, based upon valuation information obtained in connection
with the Magnolia Holding transaction, SCH recorded impairment losses associated
with the Knology investment totaling $4.8 million, net of taxes.
Derivatives
SFAS 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 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
(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
quotations 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, 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
that are allowed.
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 are used to hedge risks associated
with fixed price obligations 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 recognized gains of approximately $5.8 million, net of tax, as
a result of qualifying cash flow hedges related to nonregulated operations
during the six months ended June 30, 2003. No such gains were recognized during
the three months ended June 30, 2003. The Company recognized losses of
approximately $2.9 million and $21.9 million, net of tax, as a result of
qualifying cash flow hedges related to nonregulated operations during the three
and six months ended June 30, 2002. These gains and losses were recorded in cost
of gas. The Company estimates that most of the June 30, 2003 unrealized gain
balance of $0.5 million, net of tax, will be reclassified from accumulated other
comprehensive income (loss) to earnings in 2004 and 2005 as a decrease to gas
cost if market prices remain stable. As of June 30, 2003 all of the Company's
cash flow hedges settle by their terms before the end of 2006.
The Company recorded option premiums of $0.4 million and gains of $0.3
million, net of tax, as a result of qualifying fair value hedges during the
three and six months ended June 30, 2003, respectively. The premiums and gains
were recorded in cost of gas. As of June 30, 2003 all of the Company's fair
value hedges settle by their terms before the end of 2003.
On January 2, 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. The program
and any related transactions will be addressed in the NCUC's August 2003 Annual
Prudence Review. Transaction fees and any gains or losses are recorded in
deferred accounts for subsequent rate consideration.
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.
The Company also utilizes certain derivative instruments that do not
qualify as hedges. The change in fair value of these derivatives is recorded in
net income (loss), and was insignificant in the periods presented.
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 June 30, 2003 the estimated fair value of the Company's swaps totaled
$20.2 million related to combined notional amounts of $337.4 million.
In anticipation of the issuance of debt, the Company also uses interest
rate lock agreements to manage interest rate risk. Payments received or made
upon termination of interest rate lock 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 agreeement.
7. COMMITMENTS AND CONTINGENCIES
Reference is made to Note 12 of Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002. Commitments and contingencies at June 30, 2003 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 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 June 30, 2003 totaled approximately
$105 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 $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 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 $58.7 million per incident, but not
more than $6.7 million per year.
The Price-Anderson Indemnification Act expired in August 2002, but is
expected to renew with only modest changes in 2003. This has no impact on SCE&G
at present due to the "grandfathered" status of existing licensees that are
covered under the past act until such time as it is renewed.
SCE&G currently maintains policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric Insurance Limited. The policies, covering the
nuclear facility for property damage, excess property damage and outage costs,
permit 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 $8.2 million at June
30, 2003. 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 in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
June 30, 2003, SCE&G has spent approximately $18.7 million to remediate the
Calhoun Park site. Total remediation costs are estimated to be $21.2 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 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. SCE&G has spent approximately
$2.3 million related to all of these sites, and expects to spend an additional
$5.7 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 $7.6 million, which reflects the estimated
remaining liability at June 30, 2003. Amounts incurred to date that have not
been recovered through gas rates are approximately $1.3 million. Management
believes that all MGP cleanup costs incurred will be recoverable through gas
rates.
D. Long-Term Natural Gas Contract
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. A hearing under the binding arbitration
provisions of the contract is scheduled for September 2003. 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 the Company will vigorously pursue its
position in the arbitration proceedings. 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.
8. 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 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.
Disclosure of Reportable Segments
(Millions of dollars)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Three Months Ended External Intersegment Operating Net Segment
June 30, 2003 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $356 $1 $97 n/a $6,224
Gas Distribution 146 - (6) n/a 1,439
Gas Transmission 47 64 3 n/a 331
Retail Gas Marketing 77 - n/a $3 78
Energy Marketing 100 - n/a - 50
Telecommunications Investments - - n/a 32 183
All Other - 72 - (1) 368
Adjustments/Eliminations - (137) 6 40 (877)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $726 $- $100 $74 $7,796
================================== ============= ============== =============== ================= ===============
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Six Months Ended External Intersegment Operating Net Segment
June 30, 2003 Revenue Revenue Income Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $692 $3 $181 n/a $6,224
Gas Distribution 489 - 55 n/a 1,439
Gas Transmission 131 172 8 n/a 331
Retail Gas Marketing 260 - n/a $17 78
Energy Marketing 223 - n/a (2) 50
Telecommunications Investments - - n/a 33 183
All Other - 139 - (3) 368
Adjustments/Eliminations - (314) 24 113 (877)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $1,795 $- $268 $158 $7,796
================================== ============= ============== =============== ================= ===============
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Three Months Ended External Intersegment Operating Net Segment
June 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $349 $145 $86 n/a $5,609
Gas Distribution 102 17 (2) n/a 1,626
Gas Transmission 53 58 6 n/a 290
Retail Gas Marketing 62 - n/a $1 63
Energy Marketing 83 - n/a (2) 64
Telecommunications Investments - - n/a (3) 307
All Other - 1 - 4 536
Adjustments/Eliminations - (221) (1) 40 (827)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $649 $- $89 $40 $7,668
================================== ============= ============== =============== ================= ===============
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Six Months Ended External Intersegment Operating Net Segment
June 30, 2002 Revenue Revenue Income (Loss) Income (Loss) Assets
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Electric Operations $651 $293 $174 n/a $5,609
Gas Distribution 343 18 52 n/a 1,626
Gas Transmission 108 131 (3) n/a 290
Retail Gas Marketing 218 - n/a $15 63
Energy Marketing 151 - n/a (3) 64
Telecommunications Investments - - - (153) 307
All Other - 3 - 3 536
Adjustments/Eliminations - (445) 19 (124) (827)
- ---------------------------------- ------------- -------------- --------------- ----------------- ---------------
Consolidated Total $1,471 $- $242 $(262) $7,668
================================== ============= ============== =============== ================= ===============
9. SUBSEQUENT EVENTS
On July 1, 2003 the Company retired at maturity $20 million of 6.51%
medium-term notes. On July 8, 2003 the Company retired at maturity $75 million
of 6.25% medium-term notes.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
- -------------------------------------------------------------------------------
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 Company) Annual Report on Form 10-K for
the year ended December 31, 2002.
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, (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 (SEC). The
Company disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina electric restructuring efforts remain stalled, and the
state legislature adjourned for the year without considering electric
restructuring legislation. At the federal level, energy legislation passed both
houses of Congress in 2003, though significant differences exist between the
House and Senate versions. Some of the more stringent provisions of this
legislation, either currently included or expected to be debated in conference
committee, would require that one percent 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. 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 States Federal Energy Regulatory Commission
(FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design
(SMD) which proposes sweeping changes to the country's existing regulatory
framework governing transmission, open access and energy markets and will
attempt, in large measure, to standardize the national energy market. If
implemented, the proposed rule may have a significant impact on South Carolina
Electric and Gas Company's (SCE&G) 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 will 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.
Gas Distribution
Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, the 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, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect the price and impact the Company's ability to
retain large commercial and industrial customers on a monthly basis.
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 will be at the site of the natural gas-fired
generating station that SCE&G is building in Jasper County, South Carolina.
Construction of the pipeline began in March 2003, with completion expected by
the end of 2003, at a cost of approximately $32 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 it faces the same competitive pressures as gas
distribution for these classes of customers.
Retail Gas Marketing
SCANA Energy continues to maintain its position as the second largest
natural gas marketer in Georgia with a market share of approximately 25 percent
and total customers in excess of 350,000. 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 on the prices it
charges customers relative to 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 created 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 rates subsidized by Georgia's Universal Service Fund,
and extends service to high credit risk customers who have been denied service
by other marketers. At June 30, 2003 approximately 24,000 of SCANA Energy's
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 other natural gas marketers 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 request with FERC to obtain a declaratory order on whether FERC
regulation would preempt or have jurisdiction over SCANA Energy's proposal. The
GPSC has not yet filed the request with FERC. After FERC issues a declaratory
order, the GPSC is expected to evaluate the order and determine what action, if
any, the GPSC should take on SCANA Energy's proposal.
SCANA Energy and SCANA's other natural gas distribution, transmission and
marketing segments maintain gas inventory and also utilize forward contracts and
financial instruments, including futures contracts and options, to manage their
exposure to fluctuating commodity natural gas prices. As a part of this risk
management process, at any given time, a portion of SCANA's projected natural
gas needs has been purchased or otherwise placed under contract. Since SCANA
Energy operates in a competitive market, it may be unable to sustain its current
level of customers and/or pricing, thereby reducing expected margins and
profitability.
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. Sales of additional equity securities may also
occur. 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 June
30, 2003 was 1.82.
Cash requirements for SCANA's regulated subsidiaries arise primarily from
their operational needs, funding their construction programs and payment of
dividends to SCANA. The ability of the regulated subsidiaries to replace
existing plant investment, as well as to expand to meet future demand for
electricity 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 six months ended
June 30, 2003 and 2002:
- --------------------------------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------------ -------------
Net cash provided from operating activities $242 $188
Net cash used for financing activities (69) (39)
Cash provided from sale of investments and assets 65 336
Funds used for investments (8) (20)
Cash and temporary investments available at the beginning of the period 374 192
Funds used for utility property additions and construction expenditures,
net of noncash allowance for funds used during construction $(380) $(269)
Funds used for nonutility property additions (4) (7)
CAPITAL TRANSACTIONS
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 of 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. On July 8, 2003 the Company retired at maturity $75 million
of 6.25% medium-term notes.
CAPITAL PROJECTS
In May 2002 SCE&G began construction of an 875 megawatt generation
facility in Jasper County, South Carolina to supply electricity to its South
Carolina customers. The facility will include three natural gas
combustion-turbine generators and one steam-turbine generator. The $450 million
facility is expected to begin commercial operation in mid-2004. SCG will
transport natural gas to the facility.
In October 1999 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 June
30, 2003 totaled approximately $105 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 June 30, 2003 SCE&G has not yet
borrowed under the agreement.
ENVIRONMENTAL MATTERS
For information on environmental matters see Note 7C of Notes to
Condensed Consolidated Financial Statements.
OTHER MATTERS
Nuclear Station License Extension
In August 2002 SCE&G filed an application with the Nuclear Regulatory
Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear
Station (Summer Station). If approved, the extension would allow the plant to
operate through 2042. At June 30, 2003 SCE&G had capitalized approximately $9
million related to the application process and expects to capitalize an
additional $3 million. SCE&G expects the extension to be issued in mid-2004.
Telecommunications Investments
On May 9, 2003, the Company's investment in ITC Holding Company, Inc. was
sold. The transaction resulted in the receipt of net after-tax cash proceeds of
approximately $46 million and the receipt of an investment interest in a newly
formed entity, Magnolia Holding Company LLC, valued at approximately $8 million.
A book gain, net of tax, of approximately $37 million was realized upon
consummation of this transaction.
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
June 30, 2003 is approximately $4 million, and through June 30, 2003, they have
generated and passed through to SCE&G approximately $74 million in such tax
credits. In addition, 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. PrimeSouth
does not benefit from any synfuel tax credits.
Under a plan approved by the SCPSC, any tax credits generated and
ultimately passed through SCE&G from synfuel produced 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, 2003 the Internal Revenue Service (IRS) announced that it is
reviewing the scientific validity of certain test procedures and results that
have been presented by other taxpayers as evidence that solid coal-based
synthetic fuels have undergone a significant chemical change. Pending completion
of this review, the IRS has 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. After the IRS concludes its
review, which may occur before the end of 2003, the IRS may seek to disallow
synfuel tax credits retroactively, prospectively or both. Although one of the
partnerships in which SCE&G owns an interest is currently under audit by 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, to the extent the IRS disallows synfuel tax credits, there would not
be a material adverse effect on the Company's or SCE&G's financial position,
results of operations or cash flows.
RESULTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 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, 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 considers net earnings from
operations to be a relevant measure in assessing the Company's fundamental
earnings in that it provides investors with improved transparency of financial
information and more meaningful comparability of period-over-period analysis.
Earnings Per Share
Net earnings from operations per share of common stock for the second
quarter and year to date periods ended June 30, 2003 and 2002 were as follows:
- ------------------------------------------------------------------------------------------- -------------------------
Second Quarter Year to Date
2003 2002 2003 2002
- ------------------------------------------------------------------------------ ------------ ------------ ------------
Earnings (loss) per share $.67 $.38 $1.42 $(2.50)
Less: Realized gain from sale of telecommunications investments .33 - .33 .10
Investment impairments (.04) (.07) (.04) (1.59)
Sale of assets - .09 - .09
Cumulative effect of accounting change, net of taxes -
- - (2.20)
- ------------------------------------------------------------------------------ ------------ ------------ ------------
Net earnings from operations per share $.38 $.36 $1.13 $1.10
============================================================================== ============ ============ ============
Second Quarter 2003 vs 2002
Net earnings from operations per share increased $.02 primarily due to
improved electric margins of $.12 and improved gas margins of $.06. These
factors were partially offset by higher operation and maintenance expenses of
$.06, higher property taxes of $.02, higher depreciation and amortization
expense of $.03 and the dilutive effect of additional shares outstanding of
$.04.
Earnings per share for 2003 includes a gain of $.33 per share in connection
with the sale of ITC Holding shares and the receipt of an investment interest in
a newly formed entity (Magnolia Holding) in May 2003. In the second quarter of
2003 the Company recorded an impairment charge of $.04 per share related to the
Knology preferred stock investment. In April 2002 the Company recorded a $.09
per share gain from the sale of a subsidiary's radio service network. In June
2002 the Company recorded an impairment write-down of $.07 per share related to
the other than temporary decline in market value of the Company's investment in
Deutsche Telekom AG (DTAG).
Year to Date 2003 vs 2002
Net earnings from operations per share increased $.03 primarily due to
higher electric margins of $.24 and higher gas margins of $.18. These factors
were partially offset by higher operations and maintenance expenses of $.16,
higher depreciation and amortization expenses of $.07, higher property taxes of
$.04, the dilutive effect of additional shares outstanding of $.08 and lower AFC
of $.03.
Year to date earnings (loss) per share include the items described in the
second quarter above. In addition, earnings (loss) per share for 2002 include a
gain of $.10 per share in connection with the sale of DTAG shares in March 2002.
In March 2002 the Company also recorded an impairment write-down of $1.52 per
share related to the other than temporary decline in market value of the
Company's investment in DTAG and the $0.07 impairment described above in the
second quarter. Also, as required by SFAS 142 the Company recorded an impairment
charge of $2.20 per share, effective January 1, 2002, related to the acquisition
adjustment associated with Public Service Company of North Carolina,
Incorporated (PSNC Energy). The charge was recorded as the cumulative effect of
an accounting change.
Pension Income
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 for 2003 decreased significantly
compared to corresponding periods in 2002 primarily as a result of declines in
the value of investments through 2002. Pension income during these periods was
recorded on the Company's financial statements as follows:
- ------------------------------------------------------------------------------------ -------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 2003 2002
- ------------------------------------------------------------------------ ----------- --------- ---------
- ------------------------------------------------------------------------ ----------- --------- ---------
Income Statement Impact:
(Increase) decrease in employee benefit costs $(1.2) $3.3 $(2.3) $6.9
Increase in other income 1.9 1.8 3.9 3.9
Balance Sheet Impact:
(Increase) decrease in capital expenditures (0.3) 1.0 (0.6) 1.9
(Increase) decrease in amount due to Summer Station co-owner (0.1) 0.3 (0.1) 0.6
- ------------------------------------------------------------------------ ----------- --------- ---------
- ------------------------------------------------------------------------ ----------- --------- ---------
Total Pension Income $0.3 $6.4 $0.9 $13.3
======================================================================== =========== ========= =========
Allowance for Funds Used During Construction (AFC)
AFC is a utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is shown on the
balance sheet as construction work in progress) is capitalized. The Company
includes an equity portion of AFC in nonoperating income and a debt portion of
AFC in interest charges (credits) as noncash items, both of which have the
effect of increasing reported net income. The decrease in AFC for the three and
six months ended June 30, 2003 is primarily the result of the completion of the
Urquhart Station repowering project in June 2002. In addition, in January 2003
the SCPSC issued an order allowing SCE&G to include all Jasper County Generating
project expenditures as of December 31, 2002 and other construction work in
progress expenditures as of June 30, 2002 in electric rate base. At the time the
expenditures were included in rate base, AFC was no longer calculated on those
amounts. These decreases were partially offset by increased construction
expenditures related to the Jasper County Generating Station project in 2003 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 2003:
- -------------------- -------------------- -------------------- ----------------
Declaration Date Dividend Per Share Record Date Payment Date
- -------------------- -------------------- -------------------- ----------------
February 20, 2003 $.345 March 10, 2003 April 1, 2003
May 1, 2003 $.345 June 10, 2003 July 1, 2003
July 31, 2003 $.345 September 10, 2003 October 1, 2003
- -------------------- -------------------- -------------------- ----------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G, South
Carolina Generating Company, Inc. (GENCO) and South Carolina Fuel Company (Fuel
Company). Changes in the electric operations sales margins were as follows:
-------------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
-------------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------------
Operating revenues $356.3 $348.5 $7.8 2.2% $692.3 $651.1 $41.2 6.3%
Less: Fuel used in generation 80.0 91.5 (11.5) (12.6%) 160.8 165.9 (5.1) (3.1%)
Purchased power 15.6 16.3 (0.7) (4.3%) 26.1 21.4 4.7 22.0%
------------------------------------------------------------------ ---------------------------------
Margin $260.7 $240.7 $20.0 8.3% $505.4 $463.8 $41.6 9.0%
=========================================================================================================================
Second Quarter 2003 vs 2002
Margin increased by $21.3 million due to the increase in retail electric
base rates approved in January 2003 and by $7.4 million due to customer growth
and increased consumption. These increases were partially offset by $7.9 million
due to less favorable weather. Fuel used in generation and purchased power
decreased due to milder weather that resulted in a 1.6% decline in total
kilowatt-hour sales.
Year to Date 2003 vs 2002
Margin increased by $30.1 million due to the increase in retail electric
base rates approved in January 2003 and by $13.8 million due to customer growth
and increased consumption. These increases were partially offset by $2.3 million
due to the effects of less favorable weather. Fuel used in generation decreased
and purchased power increased due to several planned outages at steam plants
during the first quarter of 2003.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC Energy. Changes in the gas distribution sales margins, including
transactions with affiliates, were as follows:
- --------------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
- --------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------
Operating revenues $145.6 $102.5 $43.1 42.0% $488.9 $343.5 $145.4 42.3%
Less: Gas purchased for resale 102.3 60.9 41.4 68.0% 333.8 201.0 132.8 66.1%
- ------------------------------------------------------------------- ----------------------------------
Margin $43.3 $41.6 $1.7 4.1% $155.1 $142.5 $12.6 8.8%
==========================================================================================================================
Second Quarter 2003 vs 2002
Margin increased primarily due to increased recovery of environmental
remediation expenses of $0.3 million (offset in operations and maintenance) and
customer growth and increased consumption of $2.8 million, partially offset by a
decrease in industrial usage of $1.4 million due to an unfavorable competitive
position of natural gas relative to alternate fuels.
Year to Date 2003 vs 2002
Margin increased primarily due to customer growth at PSNC Energy (2.8%) and
SCE&G (1.3%) and increased recovery of environmental remediation expenses of
$1.6 million (offset in operations and maintenance), partially offset by a
second quarter decrease in industrial usage of $2.3 million due to an
unfavorable competitive position of natural gas relative to alternate fuels.
Gas Transmission
Gas Transmission is comprised of the operations of SCPC. Changes in the
gas transmission sales margins, including transactions with affiliates, were as
follows:
- ----------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
- ----------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------
Operating revenues $110.1 $110.9 $(0.8) (0.7%) $302.5 $239.0 $63.5 26.6%
Less: Gas purchased for resale 99.1 98.4 0.7 0.7 278.4 227.0 51.4 22.6%
- --------------------------------------------------------------- ----------------------------------
----------------------------------
Margin $11.0 $12.5 $(1.5) (12.0%) $24.1 $12.0 $12.1 *
==========================================================================================================================
*Greater than 100%
Second Quarter 2003 vs 2002
Margin decreased primarily due to an unfavorable competitive position of
natural gas relative to alternate fuels and decreased demand for natural gas as
a fuel for electric generation due to milder weather.
Year to Date 2003 vs 2002
Margin increased primarily due to the favorable competitive position of
natural gas relative to alternate fuels in the first quarter of $13.6 million,
partially offset by the unfavorable competitive position of natural gas relative
to alternate fuels in the second quarter of $1.5 million.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy. Changes in Retail Gas
Marketing revenues and net income (loss) were as follows:
- --------------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
- --------------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------
Operating revenues $76.5 $62.0 $14.5 23.4% $260.2 $218.2 $42.0 19.2%
Net income (loss) 3.4 (0.3) 3.7 * 16.6 13.4 3.2 23.9%
==========================================================================================================================
*Greater than 100%
Second Quarter 2003 vs 2002 Operating revenues increased primarily as a
result of increased volumes and higher average retail prices. Net income
increased primarily due to higher margins of $5.3 million partially offset by
increased bad debt expense of $0.6 million and increased interest and operating
expenses of $0.3 million.
Year to Date 2003 vs 2002 Operating revenues increased primarily as a
result of increased volumes and higher average retail prices. Net income
increased primarily due to higher margins of $6.0 million partially offset by
increased bad debt expense of $0.7 million, increased interest expense of $0.5
million and higher operating expense of $0.8 million.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Changes in energy marketing operating
revenues, including transactions with affiliates, and net income (loss) were as
follows:
- ----------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
- ----------------------------------------------------------------------------------------------------------
-----------------------------------------------------
Operating revenues $100.6 $82.6 $18.0 21.8% $223.0 $150.5 $72.5 48.2%
Net income (loss) 0.1 (1.1) 1.2 * (1.7) (2.0) 0.3 (15.0%)
==========================================================================================================
*Greater than 100%
Second Quarter 2003 vs 2002
Operating revenues increased primarily as a result of increased commodity
natural gas prices. Net income increased primarily due to higher margins.
Year to Date 2003 vs 2002
Operating revenues increased primarily as a result of increased commodity
natural gas prices. Net loss decreased primarily as a result of lower operating
and interest expenses of $2.2 million partially offset by lower margins of $1.9
million.
Other Operating Expenses
Changes in other operating expenses were as follows:
- -------------------------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
- -------------------------------------------------------------------------------------------------------------------
Other operation and maintenance $141.0 $131.4 $9.6 7.3% $285.2 $257.8 $27.4 10.6%
Depreciation and amortization 60.3 54.7 5.6 10.2% 120.2 108.4 11.8 10.9%
Other taxes 35.3 32.1 3.2 10.0% 69.8 63.3 6.5 10.3%
- ---------------------------------------------------------------- --------------------------------
Total $236.6 $218.2 $18.4 8.4% $475.2 $429.5 $45.7 10.6%
===================================================================================================================
Second Quarter 2003 vs 2002
Other operation and maintenance expenses increased primarily due to reduced
pension income of $4.5 million, increased labor and benefit costs of $2.8
million and increased healthcare costs of $1.8 million. Depreciation and
amortization increased by $4.0 million due to normal net property charges and by
$1.6 million due to completion of the Urquhart Station repowering project in
June 2002. Other taxes increased primarily due to increased property taxes.
Year to Date 2003 vs 2002
Other operation and maintenance expenses increased primarily due to reduced
pension income of $9.2 million, increased labor and benefits costs of $6.2
million, increased healthcare cost of $4.2 million, increased environmental
remediation costs of $1.6 million, increased other operating expenses for
electric generation and transmission of $2.5 million and increased bad debt
expense of $1.3 million. Depreciation and amortization increased by $7.6 million
due to normal net property additions and by $4.2 million due to the completion
of the Urquhart Station repowering project in June 2002. Other taxes increased
primarily due to increased property taxes.
Other Income (Expense)
Other income for the second quarter and year to date 2003 vs 2002,
including AFC, increased primarily due to the gain on sale of assets and
investments offset by the impairment of investments as discussed at Earnings Per
Share. In addition, other income decreased due to a reduction in AFC due to
completion of the Urquhart Station Repowering project in June 2002. In addition,
in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper
County Generating project expenditures as of December 31, 2002 and other
construction work in progress expenditures as of June 30, 2002 in electric rate
base. At the time the expenditures were included in rate base, AFC was no longer
calculated on those amounts. These decreases were partially offset by the Jasper
County Generating Station project and Lake Murray Dam Project.
Interest Expense
Second Quarter 2003 vs 2002
Interest expense remained unchanged due to lower interest rates of $7.5
million offset by $7.3 million due to increased debt and lower AFC.
Year to Date 2003 vs 2002
Interest expense remained unchanged due to lower interest rates of $9.4
million, offset by $9.8 million due to increased debt and lower AFC.
Income Taxes
Income taxes increased primarily as a result of changes in Other Income
(Expense) as discussed at Earnings Per Share.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about long-term
debt issued by the Company and other financial instruments that are sensitive to
changes in interest rates. For debt obligations the table presents principal
cash flows and related weighted average interest rates by expected maturity
dates. For interest rate swaps, the figures shown reflect notional amounts and
related maturities. Fair values for debt and swaps represent quoted market
prices.
As of June 30, 2003 Expected Maturity Date
- ------------------- ----------------------
Millions of dollars
There- Fair
Liabilities 2003 2004 2005 2006 2007 after Total Value
- --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- --------------
- --------------------------------------- -------- -------- --------- --------- --------- ---------- ---------- --------------
Long-Term Debt:
Fixed Rate ($) 251.0 202.1 197.0 177.3 71.3 2,424.2 3,322.9 3,406.8
Average Fixed Interest Rate (%) 6.39 7.51 7.37 8.58 6.94 6.39 6.64
Variable Rate ($) 150.0 150.0 149.3
Average Variable Interest Rate (%) 1.94 1.94
Interest Rate Swaps:
Pay Variable/Receive Fixed ($) 4.3 57.5 3.2 3.2 28.2 241.0 337.4 20.17
Average Pay Interest Rate (%) 7.20 6.10 4.29 4.29 4.56 3.03 3.76
Average Receive Interest Rate (%) 10.0 7.70 8.75 8.75 7.11 6.21 6.63
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 June 30, 2003 the Company held investments in the 12% senior unsecured
notes (due 2009) of a telecommunications company, the cost basis of which,
including accrued interest, is approximately $46 million. As these notes are not
actively traded, determination of their fair value is not practicable.
Commodity price risk - The following table provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu. Fair value
represents quoted market prices.
As of June 30, 2003
Millions of dollars, except weighted average settlement price and strike price
Natural Gas Derivatives: Expected Maturity in 2003 Expected Maturity in 2004 Expected Maturity in 2005
- ----------------------------
- ---------------------------- ----------- ---------- --------------------- ---------- ---------- ------------ ------------ --------
Settlement Contract Fair Settlement Contract Fair Settlement Contract Fair
Price (a) Amount Value Price (a) Amount Value Price (a) Amount Value
Futures Contracts:
Long($) 5.56 11.3 11.5 5.50 8.3 8.6 4.86 2.8 3.2
Short($) 5.62 1.4 1.3 - - - - - -
Strike Contract
Price Amount
(a)
Options:
Purchased call (long)($) 5.46 3.5
Purchased put (short) ($) 5.40 9.5
- ---------------------------- ----------- ---------- ------------------------ ------------ ----------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------------
(a) Weighted average
The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of different types. See Note 6
of Notes to Condensed Consolidated Financial Statements.
The NYMEX futures information above includes those financial positions
of both Energy Marketing and SCPC. Certain derivatives that SCPC utilizes to
hedge its gas purchasing activities are recoverable through its weighted average
cost of gas calculation. 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. The offset to the change in fair value of these derivatives is recorded
as a current asset or liability.
Beginning in January 2003, PSNC Energy initiated a hedging program for
gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs
include a provision for the recovery of actual gas costs incurred. PSNC Energy
will include the offset to the change in fair value of derivatives acquired as
part of its hedging program in deferred accounts for the over or under recovery
of gas costs. PSNC Energy will seek approval of this accounting and cost
recovery treatment from the North Carolina Utilities Commission (NCUC) during
the annual review of its gas purchasing practices in August 2003. The offset to
the change in fair value of these derivatives will be recorded as a regulatory
asset or liability.
Equity price risk - Investments in telecommunications companies' equity
securities (excluding preferred stock with significant debt characteristics) are
carried at market value or, if market value is not readily determinable, at
cost. The carrying value of the Company's investments in such securities totaled
$89.8 million at June 30, 2003. A temporary decline in value of ten percent
would result in a $9.0 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 $9.0 million
reduction in fair value and a corresponding adjustment to net income, net of tax
effect.
Item 4. Controls and Procedures
As of June 30, 2003 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 June 30, 2003 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 June 30, 2003 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)
- ----------------------------------------------------------------------------- -----------------------
June 30, December 31,
Millions of dollars 2003 2002
- ----------------------------------------------------------------------------- -----------------------
Assets
Utility Plant:
Electric $5,066 $4,934
Gas 445 439
Other 197 184
- ----------------------------------------------------------------------------- -----------------------
Total 5,708 5,557
Accumulated depreciation and amortization (1,991) (1,912)
- ----------------------------------------------------------------------------- -----------------------
Total 3,717 3,645
Construction work in progress 795 604
Nuclear fuel, net of accumulated amortization 28 38
- ----------------------------------------------------------------------------- -----------------------
Utility Plant, Net 4,540 4,287
- ----------------------------------------------------------------------------- -----------------------
Nonutility Property and Investments, Net 26 25
- ----------------------------------------------------------------------------- -----------------------
- ----------------------------------------------------------------------------- -----------------------
Current Assets:
Cash and temporary investments 81 56
Receivables, net 226 237
Receivables - affiliated companies 64 46
Inventories (at average cost):
Fuel 32 48
Materials and supplies 50 53
Emission allowances 9 10
Prepayments 27 24
- ----------------------------------------------------------------------------- -----------------------
Total Current Assets 489 474
- ----------------------------------------------------------------------------- -----------------------
Deferred Debits:
Environmental 12 18
Nuclear plant decommissioning - 87
Assets held in trust, net - nuclear decommissioning 36 -
Pension asset, net 266 265
Due from affiliates - pension and postretirement benefits 19 18
Other regulatory assets 295 267
Other 124 111
- ----------------------------------------------------------------------------- -----------------------
Total Deferred Debits 752 766
- ----------------------------------------------------------------------------- -----------------------
Total $5,807 $5,552
============================================================================= =======================
- --------------------------------------------------------------------------------- ----------------- --------------------
June 30, December 31,
Millions of dollars 2003 2002
- --------------------------------------------------------------------------------- ----------------- --------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity $1,977 $1,966
Preferred stock (Not subject to purchase or sinking funds) 106 106
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Stockholders' Investment 2,083 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 1,774 1,534
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Capitalization 3,866 3,665
- --------------------------------------------------------------------------------- ----------------- --------------------
Current Liabilities:
Short-term borrowings 212 178
Current portion of long-term debt 144 144
Accounts payable 87 124
Accounts payable - affiliated companies 83 77
Customer deposits 24 22
Taxes accrued 109 93
Interest accrued 37 31
Dividends declared 38 42
Deferred income taxes, net 2 12
Other 25 37
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Current Liabilities 761 760
- --------------------------------------------------------------------------------- ----------------- --------------------
Deferred Credits:
Deferred income taxes, net 616 610
Deferred investment tax credits 107 108
Reserve for nuclear plant decommissioning - 87
Asset retirement obligation - nuclear plant 114 -
Due to affiliates - pension and postretirement benefits 16 17
Postretirement benefits 136 131
Regulatory liabilities 124 109
Other 67 65
- --------------------------------------------------------------------------------- ----------------- --------------------
Total Deferred Credits 1,180 1,127
- --------------------------------------------------------------------------------- ----------------- --------------------
Total $5,807 $5,552
================================================================================= ================= ====================
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
- ---------------------------------------------------------------- -------------------------- -------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2003 2002 2003 2002
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Operating Revenues:
Electric $358 $350 $695 $654
Gas 64 53 204 160
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Total Operating Revenues 422 403 899 814
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Operating Expenses:
Fuel used in electric generation 71 75 140 131
Purchased power (including affiliated purchases) 34 42 65 75
Gas purchased for resale 50 40 150 112
Other operation and maintenance 100 97 202 180
Depreciation and amortization 48 42 95 84
Other taxes 31 28 61 54
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Total Operating Expenses 334 324 713 636
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Operating Income 88 79 186 178
Other Income, Including Allowance for Equity Funds
Used During Construction of $4, $6, $8 and $11 8 10 15 19
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Income Before Interest Charges, Income Taxes and
Preferred Stock Dividends 96 89 201 197
Interest Charges, Net of Allowance for Borrowed
Funds Used During Construction of $2, $3, $4 and $7 34 29 66 57
Dividend Requirement of Company -
Obligated Mandatorily Redeemable Preferred Securities 1 1 2 2
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Income Before Income Taxes and Preferred Stock Dividends 61 59 133 138
Income Taxes 21 19 46 46
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Net Income 40 40 87 92
Preferred Stock Cash Dividends Declared (At stated rates) 2 2 4 4
- ---------------------------------------------------------------- ------------ ------------- ------------- -----------
Earnings Available for Common Stockholder $38 $38 $83 $88
================================================================ ============ ============= ============= ===========
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- -------------------------------------------------------------------------------------------- ----------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002
- -------------------------------------------------------------------------------------------- -------------- -------------
Cash Flows From Operating Activities:
Net income $87 $92
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization 95 84
Amortization of nuclear fuel 12 7
Allowance for funds used during construction (12) (18)
Over (under) collections, fuel adjustment clauses 25 (11)
Changes in certain assets and liabilities:
(Increase) decrease in receivables (7) (36)
(Increase) decrease in inventories 20 (6)
(Increase) decrease in prepayments (3) (15)
(Increase) decrease in pension asset (1) (13)
(Increase) decrease in other regulatory assets (18) (1)
Increase (decrease) in deferred income taxes, net (4) 11
Increase (decrease) in regulatory liabilities 21 18
Increase (decrease) in postretirement benefits 5 5
Increase (decrease) in accounts payable (31) 5
Increase (decrease) in taxes accrued 16 (59)
Increase (decrease) in interest accrued 6 6
Changes in other assets (2) (15)
Changes in other liabilities 6 5
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Provided From Operating Activities 215 59
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (304) (238)
Proceeds from sales of assets - 1
Increase in nonutility property - (1)
Increase in investments (8) (3)
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Used For Investing Activities (312) (241)
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 495 295
Other long-term debt 2 -
Capital contribution from parent - 3
Repayments:
Mortgage Bonds (250) (104)
Other long-term debt (8) (2)
SCE&G Trust I Preferred Securities (50) -
Payment of deferred financing costs (21) -
Dividends and distributions:
Common stock (76) (75)
Preferred stock (4) (4)
Short-term borrowings, net 34 48
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Cash Provided From Financing Activities 122 161
- -------------------------------------------------------------------------------------------- ------------- --------------
Net Increase (Decrease) In Cash and Temporary Investments 25 (21)
Cash and Temporary Investments, January 1 56 37
- -------------------------------------------------------------------------------------------- ------------- --------------
Cash and Temporary Investments, June 30 $81 $16
============================================================================================ ============= ==============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $4 and $7) $60 $84
- Income taxes - 45
See Notes to Condensed Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2003
(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. 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. 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 revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result the Company has
recorded, as of June 30, 2003, approximately $307 million and $124 million of
regulatory assets and liabilities, respectively, as shown below.
June 30, December 31,
Millions of dollars 2003 2002
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Accumulated deferred income taxes, net $86 $86
Under-collections - fuel adjustment clauses 24 50
Deferred environmental remediation costs 12 18
Asset retirement obligation - nuclear decommissioning 51 -
Deferred non-conventional fuel tax benefits, net (52) (40)
Storm damage reserve (34) (32)
Franchise agreements 64 65
Other 32 29
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Total $183 $176
===============================================================================
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 - fuel adjustment clauses represent amounts
under-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, and such costs, totaling approximately $12
million, are expected to be fully recovered by the end of 2005.
Asset retirement obligation - nuclear decommissioning represents the
regulatory asset associated with the legal obligation of decommissioning and
dismantling V. C. Summer Nuclear Station (Summer Station) as required in SFAS
143, "Accounting for Asset Retirement Obligations." (See Note 1B).
Deferred non-conventional fuel tax benefits represent the deferral of
partnership losses and other expenses, offset by the accumulated deferred income
tax credits associated with two of the Company's partnerships involved in
converting coal to alternate fuel. Under a plan approved by the SCPSC, any tax
credits generated from non-conventional fuel produced 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 ten-year period. 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 the next 15 years.
The SCPSC has reviewed and approved through specific orders most of the
items shown as regulatory assets. Other items represent costs which are not yet
approved for recovery by the SCPSC. In recording these costs as regulatory
assets, management believes the costs will be allowable under existing
rate-making concepts that are embodied in rate orders received by 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 in the period the write-off would be recorded, but it is not expected
that cash flows or financial position would be materially adversely affected.
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 June 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
June 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 36 39 35
Within other regulatory assets 51 45 42
------------- ---------------- -------
------------- ---------------- -------
Total $114 $111 $105
============= ================ =======
============= ================ =======
Liabilities:
Asset retirement obligation -
nuclear plant decommissioning $114 $111 $105
============ ============== ===========
Proforma net income (loss) for periods prior to the adoption of SFAS
143 would not differ from amounts actually recorded during these periods.
In addition to the ARO for Summer Station, 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 $18.3 million and
$29.6 million payable to SCPC for such gas purchases at June 30, 2003 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 $8.5 million and $9.0 million, payable to GENCO for unit power
purchases at June 30, 2003 and December 31, 2002, respectively. Such unit power
purchases, which are included in "Purchased power", amounted to approximately
$20.9 million and $39.2 million for the three and six months ended June 30,
2003, respectively, and $27.9 million and $53.7 million for the three and six
months ended June 30, 2002, 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 affiliated companies for these investments approximately $15.5
million and $8.5 million at June 30, 2003 and December 31, 2002, respectively.
The Company had recorded as payables to affiliated companies for these
investments approximately $13.2 million and $8.0 million at June 30, 2003 and
December 31, 2002, respectively.
D. 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 an 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 May 2002 the SCPSC issued an order approving 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 increase reflects 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. 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 January 2003, in conjunction with the approval of the above 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 above appeal to the
Circuit Court of the SCPSC's May 2002 order.
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, 2002 through June 30, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002
$.928 March-June 2003 $.728 November-December 2002
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). 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 2002, as a result of the annual review, the SCPSC reaffirmed the
Company's billing surcharge of 3.0 cents per therm, which is intended to provide
for the recovery, prior to the end of the year 2005, of the balance remaining at
June 30, 2003 of $12.3 million.
3. LONG-TERM DEBT
On January 23, 2003 the Company issued $200 million of 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 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 uses interest rate
lock agreements to manage interest rate risk. Payments received or made upon
termination of interest rate lock 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 agreeement.
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 June 30, 2003 approximately $42.4 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 Notes to Consolidated Financial
Statements appearing in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002. Commitments and Contingencies at June 30, 2003 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 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 June 30, 2003 totaled
approximately $105 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 $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 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 $58.7 million per incident,
but not more than $6.7 million per year.
The Price-Anderson Indemnification Act expired in August 2002, but is
expected to renew with only modest changes in 2003. This has no impact on the
Company at present due to the "grandfathered" status of existing licensees that
are covered under the past act until such time as it is renewed.
The Company currently maintains policies (for itself and on behalf of
Santee Cooper) with Nuclear Electric Insurance Limited. The policies, covering
the nuclear facility for property damage, excess property damage and outage
costs, permit 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 $8.2
million at June 30, 2003. 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 in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
June 30, 2003, the Company has spent approximately $18.7 million to remediate
the Calhoun Park site. Total remediation costs are estimated to be $21.2
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. 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.
The Company has spent approximately $2.3 million related to all of these sites,
and expects to spend an additional $5.7 million.
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 consolidated total assets. Intersegment revenues were
not significant.
Disclosure of Reportable Segments
(Millions of Dollars)
Three months ended
June 30, 2003 2002
- ------------------------------- ---------------------------------------- ----------------------------------------
- ------------------------------- ----------- ---------------- -----------
External Operating Segment External Operating Segment
Revenue Income (Loss) Assets Revenue Income (Loss) Assets
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
------------ -------------- ------------
Electric Operations $358 $93 $5,865 $350 $83 $5,306
Gas Distribution 64 (5) 454 53 (4) 435
All Other - - - - - 4
Adjustments/Eliminations - - (512) - - (541)
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
Consolidated Total $422 $88 $5,807 $403 $79 $5,204
=============================== =========== ================ =========== ============ ============== ============
Six months ended
June 30, 2003 2002
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
External Operating Segment External Operating Segment
Revenue Income Assets Revenue Income (Loss) Assets
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
Electric Operations $695 $174 $5,865 $654 $167 $5,306
Gas Distribution 204 12 454 160 12 435
All Other - - - - - 4
Adjustments/Eliminations - - (512) - (1) (541)
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
- ------------------------------- ----------- ---------------- ----------- ------------ -------------- ------------
Consolidated Total $899 $186 $5,807 $814 $178 $5,204
=============================== =========== ================ =========== ============ ============== ============
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.
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, (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 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 (SEC). SCE&G disclaims any obligation to update any
forward-looking statements.
COMPETITION
Electric Operations
In South Carolina electric restructuring efforts remain stalled, and the
state legislature adjourned for the year without considering electric
restructuring legislation. At the federal level, energy legislation passed both
houses of Congress in 2003, though significant differences exist between the
House and Senate versions. Some of the more stringent provisions of this
legislation, either currently included or expected to be debated in conference
committee, would require that one percent 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. 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 States Federal Energy Regulatory Commission
(FERC) issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design
(SMD) which proposes sweeping changes to the country's existing regulatory
framework governing transmission, open access and energy markets and will
attempt, in large measure, to standardize the national energy market. If
implemented, the proposed rule may 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, 2003 FERC issued a "white
paper" regarding SMD which describes how the final SMD rule will differ from the
NOPR. SCE&G is currently evaluating FERC's actions to determine potential
effects on SCE&G's operations. Additional directives from FERC are expected.
Gas Distribution
Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, the 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, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect the price and impact SCE&G's ability to retain
large commercial and industrial customers on a monthly basis.
LIQUIDITY AND CAPITAL RESOURCES
SCE&G's cash requirements arise primarily from its operational needs,
funding its construction program 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 an 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 six months ended
June 30, 2003 and 2002:
- ------------------------------------------------------------------------------------ ----------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------------------ --------------- ------------
Net cash provided from operating activities $215 $59
Net cash provided from financing activities 122 161
Funds used for investments (8) (3)
Cash and temporary cash investments available at the beginning of the period 56 37
Funds used for utility property additions and construction expenditures, net of
noncash allowance for funds used during construction $(304) $(238)
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 June 30, 2003 was 3.33.
CAPITAL TRANSACTIONS
On January 23, 2003 SCE&G issued $200 million of First Mortgage Bonds
having an annual interest rate of 5.80% and maturing January 15, 2033. The
proceeds from the sale of these bonds 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 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.
CAPITAL PROJECTS
In May 2002 SCE&G began construction of an 875 megawatt generation
facility in Jasper County, South Carolina to supply electricity to its South
Carolina customers. The facility will include three natural gas
combustion-turbine generators and one steam-turbine generator. The $450 million
facility is expected to begin commercial operation in mid-2004, and SCG
Pipeline, Inc., an affiliate, will transport natural gas to the facility.
In October 1999 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 June
30, 2003 totaled approximately $105 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 June 30, 2003 SCE&G has not yet
borrowed under the agreement.
Environmental Matters
For information on environmental matters see Note 5C of Notes To
Condensed Consolidated Financial Statements.
Other Matters
Nuclear Station License Extension
In August 2002 SCE&G filed an application with the Nuclear Regulatory
Commission (NRC) for a 20-year license extension for its V. C. Summer Nuclear
Station (Summer Station). If approved, the extension would allow the plant to
operate through 2042. At June 30, 2003 SCE&G had capitalized approximately $9
million related to the application process and expects to capitalize an
additional $3 million. SCE&G expects the extension to be granted in mid-2004.
Off-Balance Sheet Arrangement
During the formation of South Carolina Generating Company, Inc. (GENCO)
(a wholly owned subsidiary of SCANA) in 1994, SCE&G's $36 million Berkeley
County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were
transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition,
holders of Berkeley Bonds may have recourse against SCE&G in the event of
default by GENCO.
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
June 30, 2003 is approximately $4 million, and through June 30, 2003, they have
generated and passed through to SCE&G approximately $74 million in such tax
credits.
Under a plan approved by the SCPSC, any tax credits generated and
ultimately passed through SCE&G from synfuel produced 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, 2003 the Internal Revenue Service (IRS) announced that it is
reviewing the scientific validity of certain test procedures and results that
have been presented by other taxpayers as evidence that solid coal-based
synthetic fuels have undergone a significant chemical change. Pending completion
of this review, the IRS has 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. After the IRS concludes its
review, which may occur before the end of 2003, the IRS may seek to disallow
synfuel tax credits retroactively, prospectively or both. Although one of the
partnerships in which the Company owns an interest is currently under audit by
the IRS, there have been no issues raised with respect to the validity of
synthetic fuel tax credits. While the Company is not able to determine what
conclusion the IRS will reach, to the extent the IRS disallows synfuel tax
credits, there would not be a material adverse effect on the Company's financial
position, results of operations or cash flows.
RESULTS OF OPERATIONS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2003
AS COMPARED TO THE CORRESPONDING PERIODS IN 2002
Net Income
Net income for the second quarter and year to date periods ended June
30, 2003 and 2002 was as follows:
- -----------------------------------------------------------------------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
- -------------------------------- ---------- ------------------------------ -------- -----------------
--------- ---------- ---------- ---------
Net income $39.9 $39.4 $0.5 1.3% $87.0 $91.4 $(4.4) (4.8%)
- -------------------------------- ---------- ---------- ------------------- -------- ------- ---------
Second Quarter 2003 vs 2002
Net income increased slightly due to higher electric margins of $20.8
million and higher gas margins of $0.4 million which were partially offset by
higher operation and maintenance expense of $4.0 million, higher depreciation
expense of $5.1 million, higher interest expense of $4.9 million, higher
property taxes of $2.6 million and lower equity AFC of $1.6 million.
Year to Date 2003 vs 2002
Net income decreased primarily due to higher operation and maintenance
expense of $22.1 million, higher depreciation expense of $10.9 million, higher
interest expense of $9.0 million, higher property taxes of $5.1 million and
lower equity AFC of $3.5 million, which were partially offset by higher electric
margins of $41.8 million and higher gas margins of $5.9 million.
Pension Income
For the last several years, the market value of SCE&G's retirement plan
(pension) assets has exceeded the total actuarial present value of accumulated
plan benefits. Pension income for 2003 decreased significantly compared to
corresponding periods in 2002 primarily as a result of declines in the value of
investments through 2002. Pension income during these periods was recorded on
SCE&G's financial statements as follows:
- --------------------------------------------------------------------------- -------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 2003 2002
- ---------------------------------------------------------------- ---------- ---------- ---------
- ---------------------------------------------------------------- ---------- ---------- ---------
Income Statement Impact:
(Increase) Decrease in employee benefit costs $(0.8) $3.1 $(1.4) $6.5
Increase in other income 1.9 1.8 3.9 3.9
Balance Sheet Impact:
(Increase) Decrease in capital expenditures (0.2) 1.0 (0.4) 1.9
(Increase) Decrease in amount due to Summer
Station co-owner (0.1) 0.3 (0.1) 0.6
- ---------------------------------------------------------------- ---------- ---------- ---------
- ---------------------------------------------------------------- ---------- ---------- ---------
Total Pension Income $0.8 $6.2 $2.0 $12.9
================================================================ ========== ========== =========
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 decrease in AFC for the three and six months
ended June 30, 2003 is primarily the result of the completion of the Urquhart
Station repowering project in June 2002. In addition, in January 2003 the SCPSC
issued an order allowing SCE&G to include all Jasper County Generating project
expenditures as of December 31, 2002 and other construction work in progress
expenditures as of June 30, 2002 in electric rate base. At the time the
expenditures were included in rate base, AFC was no longer calculated on those
amounts. These decreases were partially offset by increased construction
expenditures related to the Jasper County Generating Station project in 2003 and
the Lake Murray Dam project (see discussion at CAPITAL PROJECTS).
Dividends Declared
SCE&G's Board of Directors has declared the following dividends on
common stock held by SCANA during 2003:
------------------- ----------------- --------------------- -----------------
Declaration Date Amount Quarter Ended Payment Date
------------------- ----------------- --------------------- -----------------
February 20, 2003 $35.3 million March 31, 2003 April 1, 2003
May 1, 2003 $36.5 million June 30, 2003 July 1, 2003
July 31, 2003 $37.0 million September 30, 2003 October 31, 2003
----------------------- ----------------- --------------------- -------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and
South Carolina Fuel Company, Inc. Changes in the electric operations sales
margins were as follows:
---------------------------------- -------------------------------------- -----------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
---------------------------------- --------- --------- ------------------ ---------- ---------- -------------------
---------------------------------- --------- --------- ------- ---------- ---------- ---------- -------- ----------
Operating Revenues $357.8 $349.6 $8.2 2.3% $695.2 $653.9 $41.3 6.3%
Less: Fuel used in generation 70.8 75.2 (4.4) (5.9%) 139.9 130.7 9.2 7.0%
Purchased power 33.9 42.1 (8.2) (19.5%) 65.3 75.0 (9.7) (12.9%)
---------------------------------- --------- --------- ------- ---------- ---------- ---------- -------- ----------
---------------------------------- --------- --------- ------- ---------- ---------- ---------- -------- ----------
Margin $253.1 $232.3 $20.8 9.0% $490.0 $448.2 $41.8 9.3%
================================== ========= ========= ======= ========== ========== ========== ======== ==========
Second Quarter 2003 vs 2002
Margin increased by $20.4 million due to the increase in retail electric
base rates approved in January 2003 and by customer growth of $7.4 million
partially offset by less favorable weather of $7.9 million. Fuel used in
generation and purchased power decreased due to milder weather that resulted in
a 1.6% decline in total kilowatt-hour sales.
Year to Date 2003 vs 2002
Margin increased by $30.1 million due to the increase in retail electric
base rates approved in January 2003 and by $13.8 million due to customer growth
and increased consumption partially offset by the effects of less favorable
weather of $2.3 million. Fuel used in generation increased and purchased power
decreased due to a planned outage at GENCO.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Changes in the gas distribution sales margins were as follows:
---------------------------------- --------------------------------------- ----------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
---------------------------------- --------- --------- ------------------- --------- ---------- -------------------
---------------------------------- --------- --------- --------- --------- --------- ---------- -------- ----------
Operating Revenues $63.9 $53.0 $10.9 20.6% $204.0 $160.1 $43.9 27.4%
Less: Gas purchased for resale 50.1 39.6 10.5 26.5% 150.3 112.3 38.0 33.8%
---------------------------------- --------- --------- --------- --------
--------- --------- ----------
Margin $13.8 $13.4 $0.4 3.0% $53.7 $47.8 $5.9 12.3%
================================== ========= ========= ========= ========= ========= ========== ======== ==========
Second Quarter 2003 vs 2002
Margin increased primarily due to increased recovery of environmental
remediation expenses (offset in operations and maintenance) of $0.3 million and
customer growth and increased consumption of $1.3 million, partially offset by a
decrease in industrial usage of $1.2 million due to an unfavorable competitive
position of natural gas relative to alternate fuels.
Year to Date 2003 vs 2002
Margin increased primarily due to customer growth and increased
consumption of $1.3 million and recovery of environmental remediation expenses
of $1.6 million (offset in operations and maintenance), partially offset by a
decrease in industrial usage of $1.4 million due to an unfavorable competitive
position of natural gas relative to alternate fuels.
Other Operating Expenses
Changes in other operating expenses were as follows:
------------------------------------- -------------------------------------- -----------------------------------------
Second Quarter Year to Date
Millions of dollars 2003 2002 Change 2003 2002 Change
------------------------------------- ---------- --------- ----------------- --------- ---------- --------------------
Other operation and maintenance $100.8 $96.8 $4.0 4.1% $201.7 $179.6 $22.1 12.3%
Depreciation and amortization 47.6 42.5 5.1 12.0% 94.9 84.0 10.9 13.0%
Other taxes 30.7 27.8 2.9 10.4% 60.6 54.3 6.3 11.6%
------------------------------------- ---------- --------- ------- --------- --------- ---------- --------- ----------
------------------------------------- ---------- --------- ------- --------- --------- ---------- --------- ----------
Total $179.1 $167.1 $12.0 7.2% $357.2 $317.9 $39.3 12.4%
===================================== ========== ========= ======= ========= ========= ========== ========= ==========
Second Quarter 2003 vs 2002
Other operation and maintenance expenses increased primarily due to reduced
pension income of $3.9 million and increased labor and benefit costs of $1.1
million. Depreciation and amortization expense increased by $3.5 million due to
normal net property additions and by $1.6 million due to the completion of the
Urquhart Station repowering project in June 2002. Other taxes increased
primarily due to increased property taxes.
Year to Date 2003 vs 2002
Other operation and maintenance expenses increased primarily due to reduced
pension income of $7.9 million, increased labor and benefits costs of $4.0
million, increased healthcare cost of $4.2 million, increased environmental
remediation costs of $1.6 million and increased other operating expenses for
electric generation and transmission of $2.5 million. Depreciation and
amortization expense increased by $6.7 million due to normal net property
additions and by $4.2 million due to the completion of the Urquhart Station
repowering project in June 2002. Other taxes increased primarily due to
increased property taxes.
Other Income
Other income for second quarter and year to date 2003 vs 2002, including
AFC, decreased primarily due to completion of the Urquhart Station Repowering
project in June 2002. In addition, in January 2003 the SCPSC issued an order
allowing SCE&G to include all Jasper County Generating Project expenditures as
of December 31, 2002 and other construction work in progress expenditures as of
June 30, 2002 in electric rate base. At the time the expenditures were included
in rate base, AFC was no longer calculated on those amounts. These decreases
were partially offset by the Jasper County Generation Station project and Lake
Murray Dam Project.
Interest Expense
Second Quarter 2003 vs 2002
Interest expense increased by $6.2 million due to increased long-term debt
and by $1.3 million due to lower AFC. These increases were partially offset by
$2.4 million due to lower interest rates.
Year to Date 2003 vs 2002
Interest expense increased by $10.9 million due to increased long-term
debt and by $2.8 million due to lower AFC. These increases were partially offset
by $4.9 million due to lower interest rates.
Income Taxes
Income taxes changed primarily as a result of changes in operating income.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
All financial instruments held by SCE&G and described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about long-term
debt issued by SCE&G which is sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates. Fair values for debt represent quoted
market prices.
As of June 30, 2003
Millions of dollars Expected Maturity Date
There- Fair
Liabilities 2003 2004 2005 2006 2007 after Total Value
- ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- --------------
- ------------------------------ --------- -------- -------- -------- --------- ------------- ---------- --------------
Long-Term Debt:
Fixed Rate ($) 145.8 138.4 188.4 169.1 38.2 1,430.6 2,110.5 2,086.1
Average Interest Rate (%) 6.29 7.44 7.35 8.49 6.74 6.22 6.60
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.
Item 4. Controls and Procedures
As of June 30, 2003 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 June 30, 2003 SCE&G's disclosure controls and procedures were effective.
There has been no change in SCE&G's internal conrol over financial reporting
during the quarter ended June 30, 2003 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)
- ------------------------------------------------------------------------ -------------------
June 30, December 31,
Millions of dollars 2003 2002
- ------------------------------------------------------------------------ -------------------
Assets
Gas Utility Plant $918 $895
Accumulated depreciation (336) (318)
Acquisition adjustment, net of accumulated amortization 210 210
- ------------------------------------------------------------------------ -------------------
Gas Utility Plant, Net 792 787
- ------------------------------------------------------------------------ -------------------
Nonutility Property and Investments, Net 27 28
- ------------------------------------------------------------------------ -------------------
Current Assets:
Cash and temporary investments 4 1
Restricted cash and temporary investments 7 7
Receivables, net of allowance for uncollectible
accounts of $2 and $2 48 98
Receivables-affiliated companies 13 14
Inventories (at average cost):
Stored gas 37 38
Materials and supplies 5 6
Prepayments 1 1
Deferred income taxes, net 3 3
- ------------------------------------------------------------------------ -------------------
Total Current Assets 118 168
- ------------------------------------------------------------------------ -------------------
Deferred Debits:
Due from affiliate-pension asset 14 14
Regulatory assets 32 20
Other 6 7
- ------------------------------------------------------------------------ -------------------
Total Deferred Debits 52 41
- ------------------------------------------------------------------------ -------------------
Total $989 $1,024
======================================================================== ===================
======================================================================== ===================
Capitalization and Liabilities
Capitalization:
Common equity 503 $487
Long-term debt, net 283 286
- ------------------------------------------------------------------------ -------------------
Total Capitalization 786 773
- ------------------------------------------------------------------------ -------------------
Current Liabilities:
Short-term borrowings - 31
Current portion of long-term debt 8 8
Accounts payable 28 44
Accounts payable-affiliated companies 8 7
Customer prepayments and deposits 7 12
Taxes accrued 2 5
Interest accrued 5 6
Distributions/Dividends declared 5 5
Other 10 11
- ------------------------------------------------------------------------ -------------------
Total Current Liabilities 73 129
- ------------------------------------------------------------------------ -------------------
Deferred Credits:
Deferred income taxes, net 92 91
Deferred investment tax credits 2 2
Due to affiliate-postretirement benefits 16 16
Regulatory liabilities 9 1
Other 11 12
- ------------------------------------------------------------------------ -------------------
Total Deferred Credits 130 122
- ------------------------------------------------------------------------ -------------------
Total $989 $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 Six Months Ended
June 30, June 30,
Millions of dollars 2003 2002 2003 2002
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Operating Revenues $82 $49 $284 $183
Cost of Gas 52 21 183 88
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Gross Margin 30 28 101 95
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Operating Expenses:
Operation and maintenance 19 16 37 34
Depreciation 9 9 17 17
Other taxes 2 2 4 4
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Total Operating Expenses 30 27 58 55
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Operating Income - 1 43 40
Other Income, Including Allowance for Equity Funds
Used During Construction 2 1 4 2
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction 5 5 10 11
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Income (Loss) Before Income Tax Expense (Benefit) and Cumulative
Effect of Accounting Change (3) (3) 37 31
Income Tax Expense (Benefit) (1) (1) 14 12
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Income (Loss) Before Cumulative Effect of Accounting Change (2) (2) 23 19
Cumulative Effect of Accounting Change, Net of Taxes - - - (230)
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
- ----------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Net Income (Loss) $(2) $(2) $23 $(211)
============================================================================= ============ ============ ============ ============
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
- ---------------------------------------------------------------------------------------------- -----------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002
- ---------------------------------------------------------------------------------------------- --------------- -------------
Cash Flows From Operating Activities:
Net income (loss) $23 $(211)
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes - 230
Depreciation 18 19
Allowance for funds used during construction (1) -
Over (under) collection, gas cost adjustment clause (4) (15)
Changes in certain assets and liabilities:
(Increase) decrease in receivables, net 51 43
(Increase) decrease in inventories 2 13
Increase (decrease) in accounts payable and advances (15) (26)
Increase (decrease) in deferred income taxes, net 1 1
Increase (decrease) in taxes accrued (3) (4)
Changes in other assets 2 1
Changes in other liabilities (6) 3
- ---------------------------------------------------------------------------------------------- --------------- -------------
Net Cash Provided From Operating Activities 68 54
- ---------------------------------------------------------------------------------------------- --------------- -------------
Cash Flows From Investing Activities:
Construction expenditures (22) (24)
Nonutility and other (1) -
- ---------------------------------------------------------------------------------------------- --------------- -------------
Net Cash Used For Investing Activities ( 23) (24)
- ---------------------------------------------------------------------------------------------- --------------- -------------
Cash Flows From Financing Activities:
Repayment of short-term borrowings, net (31) -
Capital contributions from parent 2 1
Retirement of long-term debt (3) -
Distributions/Dividend payments (10) (5)
- ---------------------------------------------------------------------------------------------- --------------- -------------
Net Cash Used For Financing Activities (42) (4)
- ---------------------------------------------------------------------------------------------- --------------- -------------
Net Increase In Cash and Temporary Investments 3 26
Cash and Temporary Investments, January 1 1 18
- ---------------------------------------------------------------------------------------------- --------------- -------------
Cash and Temporary Investments, June 30 $4 $44
============================================================================================== =============== =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $0.6 and $0.5) $9 $9
- Income taxes 17 16
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
- ------------------------------------------------------------------- -------------------------- ------------------------
Three Months Ended Six Months Ended
June 30, June 30,
Millions of dollars 2003 2002 2003 2002
- ------------------------------------------------------------------- ------------- ------------ ----------- ------------
- ------------------------------------------------------------------- ------------- ------------ ----------- ------------
Net Income (Loss) $(2) $(2) $23 $(211)
Other Comprehensive Income (Loss), net of tax:
Unrealized gains (losses) on hedging activities - - - -
- ------------------------------------------------------------------- ------------- ------------ ----------- ------------
- ------------------------------------------------------------------- ------------- ------------ ----------- ------------
Total Comprehensive Income (Loss) (1) $(2) $(2) $23 $(211)
=================================================================== ============= ============ =========== ============
(1) Accumulated other comprehensive income (loss) of the Company totaled $(1.3)
million and $(1.3) million as of June 30, 2003 and December 31, 2002,
respectively.
See Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2003
(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. These are interim financial statements, and due to the
seasonality of the Company's business, the amounts reported in the Condensed
Consolidated Statements of Operations are not necessarily indicative of amounts
expected for the year. In the opinion of management, the information furnished
herein reflects all adjustments, all of a normal recurring nature, which are
necessary for a fair statement of the results for the interim periods reported.
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 revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result, the Company has
recorded as of June 30, 2003 approximately $32 million and $9 million of
regulatory assets and liabilities, respectively, as shown below.
June 30, December 31,
Millions of dollars 2003 2002
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Excess deferred income taxes $- $(1)
Under-collections-gas cost adjustment clause 14 11
Deferred environmental remediation costs 9 9
- -------------------------------------------------------------------------------
Total $23 $19
===============================================================================
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 cost adjustment clause represents amounts
under-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 represents costs associated with
the assessment and cleanup of manufactured gas plant (MGP) sites currently or
formerly owned by the Company. Management believes that all MGP cleanup costs
will be recoverable through gas rates. A portion of the costs incurred are being
recovered through rates, and management believes the remaining costs of
approximately $7.6 million will be recoverable in the future. Amounts incurred
to date that have not been recovered through gas rates are approximately $1.3
million. (See Note 5.)
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 in the period the write-off would be recorded, but it is not expected
that cash flows or financial position would be materially adversely affected.
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 an 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. SFAS 149 is not expected
to have a material impact on the Company's results of operations, cash flows or
financial position.
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. 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
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, 2002 through June 30, 2003 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002
$.595 March 2003 $.215 February-June 2002
$.725 April-June 2003 $.350 July-October 2002
$.410 November-December 2002
On April 24, 2003 the NCUC issued an order in the Company's 2002 Annual
Prudence Review. The NCUC determined that the Company's gas costs during the
12-month review period ended March 31, 2002 were reasonable and prudently
incurred. The NCUC also authorized new temporary rate decrements to refund
certain balances in deferred accounts.
On June 2, 2003 the Company filed testimony in the 2003 Annual Prudence
Review related to the 12 months ended March 31, 2003. The NCUC will hold a
hearing on August 12, 2003 to review the Company's filing.
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 million. The Madison County and Jackson
County portions of the project were completed in 2002, and the Swain County
portion is expected to be completed in the spring of 2004. Through June 30, 2003
approximately $20 million had been spent on this project.
In December 1999 the NCUC issued an order approving SCANA'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. FINANCIAL INSTRUMENTS
SFAS 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 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.
On January 2, 2003 the Company 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. The program and
any related transactions will be addressed in the August 2003 Annual Prudence
Review with the NCUC. Transaction fees and any gains or losses are recorded in
deferred accounts for subsequent rate consideration. As of June 30, 2003 the
Company had deferred a net gain of approximately $625 thousand.
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 June 30, 2003 the estimated fair value of the Company's swaps
totaled $3.3 million related to combined notional amounts of $37.4 million.
5. 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 $7.6 million, which reflects the estimated
remaining liability at June 30, 2003. Amounts incurred to date that have not
been recovered through gas rates are approximately $1.3 million. Management
believes that all MGP cleanup costs will be recoverable through gas rates.
6. 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 of dollars)
Three Months Ended
June 30, 2003 2002
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
External Operating Segment External Operating Segment
Revenue Income Assets Revenue Income Assets
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Gas Distribution $82 - $977 $49 $1 $1,170
All Other - n/a 28 - n/a 28
Adjustments/Eliminations - - (16) - - 3
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Consolidated Total $82 - $989 $49 $1 $1,201
============================== ============= ================ ============= ============= ============== =============
Six Months Ended
June 30, 2003 2002
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
External Operating Segment External Operating Segment
Revenue Income Assets Revenue Income Assets
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Gas Distribution $284 $43 $977 $183 $40 $1,170
All Other - n/a 28 - n/a 28
Adjustments/Eliminations - - (16) - - 3
------------------------------ ------------- ---------------- ------------- ------------- -------------- -------------
Consolidated Total $284 $43 $989 $183 $40 $1,201
============================== ============= ================ ============= ============= ============== =============
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.
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, (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 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 (SEC). PSNC Energy disclaims
any obligation to update any forward-looking statements.
Net Income (Loss) and Distributions/Dividends
Net income (loss) for the six months ended June 30, 2003 and 2002 was as
follows:
- -----------------------------------------------------------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002
- ---------------------------------------------------------------- ------------
Net income (loss) $22.6 $(210.4)
Less: Cumulative effect of accounting change - (229.6)
- ---------------------------------------------------------------- ------------
- ---------------------------------------------------------------- ------------
Income before cumulative effect of accounting change $22.6 $19.2
================================================================ ============
Income before cumulative effect of accounting change increased
approximately $3.4 million primarily due to increased margin of $6.8 million and
other income of $2.1 million which were partially offset by higher operating
expenses of $3.5 million and higher income taxes of $2.4 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 30 and September 30 are generally PSNC Energy's least profitable quarters
due to decreased 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
- --------------------- ---------------- ---------------------- ------------------
Gas Distribution
Gas distribution is comprised of the local distribution operations of
PSNC Energy. Changes in the gas distribution sales margins were as follows:
------------------------ -----------------------------------------
Six Months Ended
June 30,
Millions of dollars 2003 2002 Change
------------------------ --------- -------- ----------------------
------------------------ ----------
Operating revenues $284.9 $183.4 $101.5 55.3%
Less: Cost of gas 183.4 94.7 106.8%
88.7
------------------------ --------- -------- -----------
Gross margin $101.5 $94.7 $6.8 7.2%
======================== ========= ======== =========== ==========
Gas distribution sales margin for the six months ended June 30, 2003
increased primarily due to weather that was 13% colder than in 2002 and due to
customer growth of approximately 2.8%. Revenues and cost of gas increased as a
result of higher commodity natural gas prices.
Operation and Maintenance Expenses
Operation and maintenance expenses increased $3.5 million for the six
months ended June 30, 2003 compared to the same period in 2002 primarily due to
increased labor and benefits costs of $1.3 million, increased outside labor and
general business expenses of $0.9 million, increased bad debt expense of $0.6
million and the impact of reduced pension income of $0.6 million.
Other Income
Other income increased $2.1 million compared to the same period in 2002
primarily due to income from secondary market activities, such as off-system gas
sales and pipeline capacity release, and an increase in interest income 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.
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 2003 construction budget is approximately $46.7 million, compared to
actual construction expenditures for 2002 of $47.8 million. PSNC Energy's ratio
of earnings to fixed charges for the 12 months ended June 30, 2003 was 2.95.
At June 30, 2003 PSNC Energy had no outstanding short-term borrowings
and had unused lines of credit of $125 million.
Item 4. Controls and Procedures
As of June 30, 2003 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 June 30, 2003 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 June 30, 2003 that has
materially affected or is reasonably likely to materially affect PSNC Energy's
internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The following Legal Proceedings were pending at June 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 reflects 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
resolution of the above appeal to the Circuit Court of the SCPSC's May 2002
order.
On January 2, 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. The program
and any related transactions will be addressed in the August 2003 Annual
Prudence Review with the NCUC. Transaction fees and any gains or losses are
recorded in deferred accounts for subsequent rate consideration.
On June 2, 2003 PSNC Energy filed testimony in the 2003 Annual Prudence
Review related to the 12 months ended March 31, 2003. The NCUC will hold a
hearing on August 12, 2003 to review PSNC Energy's filing.
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 June 30, 2003 totaled approximately
$105 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 in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
June 30, 2003, SCE&G has spent approximately $18.7 million to remediate the
Calhoun Park site. Total remediation costs are estimated to be $21.2 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 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. SCE&G has spent approximately
$2.3 million related to all of these sites, and expects to spend an additional
$5.7 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
$7.6 million, which reflects the estimated remaining liability at June 30, 2003.
Amounts incurred to date that have not been recovered through gas rates are
approximately $1.3 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 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. A hearing under the binding arbitration
provisions of the contract is scheduled for September 2003. In initial pleadings
for the hearing, the supplier has 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 the Company will vigorously pursue its
position in the arbitration proceedings. 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 its business operations which management
anticipates will be resolved without material loss to the Company.
Item 2, 3, and 5 are not applicable.
Item 4. Submission of Matters to a Vote of Security-Holders (not applicable
for South Carolina Electric & Gas Company and Public Service Company of North
Carolina, Incorporated)
The Annual Meeting of Shareholders of SCANA Corporation Common Stock
(No Par Value) was held on May 1, 2003. The following matters were
voted upon at the meeting.
1. To elect four Class III Directors for the terms specified in the
Proxy Statement.
Number of Voting Number of Shares Total
Shares Voting Voting to Shares
Nominee For Withhold Authority Voted
James A. Bennett 91,305,994 2,798,210 94,104,204
William C. Burkhardt 92,802,195 1,302,009 94,104,204
Lynne M. Miller 92,824,202 1,280,002 94,104,204
Maceo K. Sloan 92,704,078 1,400,126 94,104,204
2. To approve the appointment of Deloitte & Touche LLP as independent
accountants for the Corporation.
Number of Shares
FOR 90,601,340
AGAINST 3,035,804
ABSTAIN 467,060
-------
TOTAL 94,104,204
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.
B. Reports on Form 8-K during the second quarter 2003 were as follows:
SCANA Corporation:
Date of report: April 25, 2003
Items reported: Items 7 and 9 (Item 12 disclosure)
South Carolina Electric & Gas Company:
Date of report: April 25, 2003
Items reported: Items 7 and 9 (Item 12 disclosure)
Date of report: May 16, 2003
Item reported: Items 5 and 7
Public Service Company of North Carolina, Incorporated:
Date of report: April 25, 2003
Item reported: Items 7 and 9 (Item 12 disclosure)
SIGNATURES
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)
August 8, 2003 By s/James E. Swan, IV
-------------------------------------
James E. Swan, IV
Controller
(Principal accounting officer)
EXHIBIT INDEX
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
2.01 X X Agreement and Plan of Merger, dated as of February 16, 1999 as amended and
restated as of May 10, 1999, by and among Public Service Company of North
Carolina, Incorporated, SCANA Corporation, New Sub I, Inc. and New Sub II, Inc.
(Filed as Exhibit 2.1 to Registration Statement No. 333-78227 on Form S-4)
3.01 X Restated Articles of Incorporation of SCANA as adopted on April 26, 1989 (Filed
as Exhibit 3-A to Registration Statement No. 33-49145)
3.02 X Articles of Amendment of SCANA, dated April 27, 1995 (Filed as Exhibit 4-B to
Registration Statement No. 33-62421)
3.03 X Restated Articles of Incorporation of SCE&G, as adopted on May 3, 2001 (Filed as
Exhibit 3.01 to Registration Statement No. 333-65460)
3.04 X Articles of Amendment of SCE&G dated as of the dates indicated below and filed as
exhibits to the Registration Statements or Exchange Act filings as set forth below
May 22, 2001 Exhibit 3.02 to Registration No. 333-65460
June 14, 2001 Exhibit 3.04 to Registration No. 333-65460
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
August 30, 2002 Exhibit 3.05 to Registration No. 333-101449
March 13, 2003 Exhibit 3.05 to Form 10-Q filed March 31, 2003
3.05 X Articles of Amendment of SCE&G dated May 22, 2003 (Filed herewith)
3.06 X Articles of Amendment of SCE&G, dated June 18, 2003 (Filed herewith)
3.07 X Articles of Correction of SCE&G dated June 1, 2001 (Filed as Exhibit 3.03 to
Registration Statement No. 333-65460)
3.08 X Articles of Incorporation of PSNC Energy (formerly New Sub II, Inc.) dated
February 12, 1999 (Filed as Exhibit 3.01 to Registration Statement No. 333-45206)
3.09 X Articles of Amendment of PSNC Energy as adopted on
February 10, 2000 (Filed as Exhibit 3.02 to Registration Statement No. 333-45206)
3.10 X Articles of Correction of PSNC Energy dated February 11, 2000 (Filed as Exhibit
3.03 to Registration Statement No. 333-45206)
3.11 X By-Laws of SCANA as revised and amended on December 13, 2000 (Filed as Exhibit
3.01 to Registration Statement No. 333-68266)
3.12 X By-Laws of SCE&G as amended and adopted on February 22, 2001 (Filed as Exhibit
3.05 to Registration Statement No. 333-65460)
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
3.13 X By-Laws of PSNC Energy as revised and amended on
February 22, 2001 (Filed as Exhibit 3.01 to Registration Statement No.
333-68516)
4.01 X Articles of Exchange of South Carolina Electric and Gas Company and SCANA
Corporation (Filed as Exhibit 4-A to Post-Effective Amendment
No. 1 to Registration Statement No. 2-90438)
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 Statement No.
33-32107)
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. 2-26459)
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 (Filed as
Exhibit 2-C to Registration Statement No. 2-26459)
4.05 X X Fifth through Fifty-third Supplemental Indentures to Indenture referred to in
Exhibit 4.03 dated as of the dates indicated below and filed as exhibits to the
Registration Statements whose file numbers are set forth below
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
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
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. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
June 1, 1986 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. 33-57955
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. 33-49421)
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. 33-49421)
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. 33-57955)
4.09 X X Indenture dated as of January 1, 1996 between PSNC Energy and First Union
National Bank of North Carolina, as Trustee (Filed as Exhibit 4.08 to
Registration Statement No. 333-45206)
4.10 X X First through Fourth Supplemental Indentures to Indenture referred to in Exhibit
4.09 dated as of the dates indicated below and filed as exhibits to the Registration
Statements whose file numbers are set forth below
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
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
4.11 X PSNC Energy $150 million medium-term note issued February 16, 2002 (Filed as
Exhibit 4.06 to Registration Statement No. 333-68516)
*10.01 X SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed
herewith)
*10.02 X SCANA Supplemental Executive
Retirement Plan as amended July
1, 2001 (Filed as Exhibit 10.02
to Form 10-Q for the quarter
ended September 30, 2001)
*10.03 SCANA Key Executive Severance
X Benefits Plan as amended July 1,
2001 (Filed as Exhibit 10.03 to
Form 10-Q for the quarter ended
September 30, 2001)
*10.04 X SCANA Supplementary Key
Executive Severance Benefits Plan
as amended July 1, 2001 (Filed as
Exhibit 10.03a to Form 10-Q for
the quarter ended September 30,
2001)
*10.05 X SCANA Long-Term Equity Compensation Plan dated January 2000 filed as Exhibit 4.04
to Registration Statement No. 333-37398)
*10.06 X Request for Action by the SCANA Long-Term Equity Compensation Plan Committee of the
Board dated August 1, 2002 (Filed herewith)
*10.07 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. 1-8809)
*10.08 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.
1-8809)
*10.09 X SCANA Corporation Director
Compensation and Deferral Plan
effective January 1, 2001 (Filed
herewith)
10.10 X Operating Agreement of Pine Needle LNG Company, LLC dated August 8, 1995 (Filed
as Exhibit 10.01 to Registration Statement No. 333-45206)
10.11 X Amendment to Operating Agreement of Pine Needle LNG Company, LLC dated October 1,
1995 (Filed as Exhibit 10.02 to Registration Statement No. 333-45206)
10.12 X Amended Operating Agreement of Cardinal Extension Company, LLC dated December 19,
1996 (Filed as Exhibit 10.03 to Registration Statement No.
333-45206)
10.13 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.
333-45206)
10.14 X Form of Severance Agreement between PSNC Energy and its Executive Officers (Filed
as Exhibit 10.05 to Registration Statement No. 333-45206)
Exhibit Applicable to Form 10-Q of
No. SCANA SCE&G PSNC Description
Energy
10.15 X Service Agreement between PSNC Energy and SCANA Services, Inc., effective April
1, 2000 (Filed as Exhibit 10.06 to Registration Statement No. 333-45206)
10.16 X Service Agreement between SCE&G and SCANA Services, Inc., effective April 1, 2002
(Filed as Exhibit 10.01 to Registration Statement No. 333-101449)
31.1 X Certification of Principal Executive Officer Required by Rule 13a-14 (Filed
herewith)
31.2 X Certification of Principal Financial Officer Required by Rule 13a-14 (Filed
herewith)
31.3 X Certification of Principal Executive Officer Required by Rule 13a-14 (Filed
herewith)
31.4 X Certification of Principal Financial Officer Required by Rule 13a-14 (Filed
herewith)
31.5 X Certification of Principal Executive Officer Required by Rule 13a-14 (Filed
herewith)
31.6 X Certification of Principal Financial Officer Required by Rule 13a-14 (Filed
herewith)
32.1 X Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350
(Filed herewith)
32.2 X Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350
(Filed herewith)
32.3 X Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350
(Filed herewith)
32.4 X Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350
(Filed herewith)
32.5 X Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350
(Filed herewith)
32.6 X Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350
(Filed herewith)
* Management Contract or Compensatory Plan or Arrangement