Ex. 99.1
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
REPORTING PACKAGE
For the year ended December 31, 2004
Contents
Page
Number
Audited Financial Statements
Report of Independent Registered Public Accounting Firm 1
Balance Sheets 2-3
Statements of Income 4
Statements of Cash Flows 5
Statements of Common Shareholder's Equity 6
Notes to Financial Statements 7
Results of Operations 22
Selected Operating Statistics 26
Basis of Presentation
These annual financial statements should be read in conjunction with audited
annual consolidated financial statements and the notes thereto of Vectren
Corporation (Vectren) and Vectren Utility Holdings, Inc. (VUHI), the parent
companies of SIGECO, filed on report Form 10-K for the year ended December 31,
2004. Vectren and VUHI make available their Securities and Exchange Commission
filings and recent annual reports free of charge through its website at
www.vectren.com.
Frequently Used Terms
AFUDC: allowance for funds used during MMBTU: millions of British thermal
construction units
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh/GWh: megawatt hours/thousands of
megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of SFAS: Statement of Financial Accounting
Environmental Management Standards
IURC: Indiana Utility Regulatory USEPA: United States Environmental
Commission Protection Agency
MCF/MMCF/BCF: thousands/millions/ Throughput: combined gas sales and gas
billions of cubic feet transportation volumes
MDth/MMDth: thousands/millions of
dekatherms
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of Southern Indiana Gas & Electric
Company:
We have audited the accompanying balance sheets of Southern Indiana Gas &
Electric Company (the "Company") as of December 31, 2004 and 2003, and the
related consolidated statements of income, common shareholder's equity, and cash
flows for the years then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Company's internal control
over financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Southern Indiana Gas & Electric Company as
of December 31, 2004 and 2003, and the results of its operations and its cash
flows for the years then ended, in conformity with accounting principles
generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
- -------------------------------------
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 23, 2005
FINANCIAL STATEMENTS
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
BALANCE SHEETS
(In thousands)
December 31,
- ------------------------------------------------------------------------------
2004 2003
- ------------------------------------------------------------------------------
ASSETS
Utility Plant
Original cost $ 1,804,843 $ 1,659,527
Less: Accumulated depreciation &
amortization 761,256 719,787
- ------------------------------------------------------------------------------
Net utility plant 1,043,587 939,740
- ------------------------------------------------------------------------------
Current Assets
Cash & cash equivalents 1,777 3,675
Accounts receivable - less reserves of
$1,148 & $1,202, respectively 55,109 38,817
Receivables from other Vectren companies 1,547 76
Accrued unbilled revenues 36,402 28,162
Inventories 36,599 37,214
Recoverable fuel & natural gas costs - 3,900
Prepayments & other current assets 7,376 4,875
- ------------------------------------------------------------------------------
Total current assets 138,810 116,719
- ------------------------------------------------------------------------------
Investments in unconsolidated affiliates 150 150
Other investments 9,481 10,474
Non-utility property - net 3,568 3,769
Goodwill - net 5,557 5,557
Regulatory assets 50,239 54,625
Other assets 85 688
- ------------------------------------------------------------------------------
TOTAL ASSETS $ 1,251,477 $ 1,131,722
==============================================================================
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
BALANCE SHEETS
(In thousands)
December 31,
- ------------------------------------------------------------------------------
2004 2003
- ------------------------------------------------------------------------------
LIABILITIES & SHAREHOLDER'S EQUITY
Capitalization
Common shareholder's equity
Common stock (no par value) $ 128,263 $ 128,258
Retained earnings 265,935 266,911
- ------------------------------------------------------------------------------
Total common shareholder's equity 394,198 395,169
- ------------------------------------------------------------------------------
Cumulative redeemable preferred stock 112 228
Long-term debt payable to third parties -
net of debt subject to tender 226,028 216,330
Long-term debt payable to VUHI 148,484 148,484
- ------------------------------------------------------------------------------
Total capitalization 768,822 760,211
- ------------------------------------------------------------------------------
Commitments & Contingencies (Notes 3, 7, 8 & 9)
Current Liabilities
Accounts payable 37,159 18,437
Accounts payable to affiliated companies 11,266 8,312
Payables to other Vectren companies 9,929 11,456
Accrued liabilities 37,803 38,619
Short-term borrowings 339 830
Short-term borrowings payable to VUHI 170,171 82,929
Long-term debt subject to tender - 9,975
- ------------------------------------------------------------------------------
Total current liabilities 266,667 170,558
- ------------------------------------------------------------------------------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 121,917 109,951
Regulatory liabilities 51,439 48,153
Deferred credits & other liabilities 42,632 42,849
- ------------------------------------------------------------------------------
Total deferred income taxes & other
liabilities 215,988 200,953
- ------------------------------------------------------------------------------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $1,251,477 $1,131,722
==============================================================================
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
STATEMENTS OF INCOME
(In thousands)
Year Ended December 31,
- ---------------------------------------------------------------------------
2004 2003
- ---------------------------------------------------------------------------
OPERATING REVENUES
Electric utility $ 371,279 $ 335,694
Gas utility 110,373 102,736
- ---------------------------------------------------------------------------
Total operating revenues 481,652 438,430
- ---------------------------------------------------------------------------
COST OF OPERATING REVENUES
Fuel for electric generation 96,132 86,477
Purchased electric energy 20,655 16,172
Cost of gas sold 78,314 73,427
- ---------------------------------------------------------------------------
Total cost of operating revenues 195,101 176,076
- ---------------------------------------------------------------------------
TOTAL OPERATING MARGIN 286,551 262,354
OPERATING EXPENSES
Other operating 112,113 102,994
Depreciation & amortization 58,484 47,649
Income taxes 31,853 30,640
Taxes other than income taxes 13,334 12,448
- ---------------------------------------------------------------------------
Total operating expenses 215,784 193,731
- ---------------------------------------------------------------------------
OPERATING INCOME 70,767 68,623
Other income - net 3,145 5,048
Interest expense 25,333 24,814
- ---------------------------------------------------------------------------
NET INCOME 48,579 48,857
- ---------------------------------------------------------------------------
Preferred stock dividends 13 23
- ---------------------------------------------------------------------------
NET INCOME APPLICABLE TO
COMMON SHAREHOLDER $ 48,566 $ 48,834
===========================================================================
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
- -------------------------------------------------------------------------------
2004 2003
- -------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 48,579 $ 48,857
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 58,484 47,649
Deferred income taxes & investment tax credits 14,937 (6,195)
Pension & postretirement periodic benefit cost 2,657 2,896
Unrealized loss (gain) on derivative instruments 1,399 (654)
Other non-cash charges - net 223 (1,521)
Changes in working capital accounts:
Accounts receivable, including to Vectren
companies & accrued unbilled revenue (27,853) 33,538
Inventories 1,228 2,439
Recoverable fuel & natural gas costs 3,900 5,715
Prepayments & other current assets (2,707) 608
Accounts payable, including to Vectren
companies & affiliated companies 20,149 (11,700)
Accrued liabilities (393) 9,458
Changes in noncurrent assets 2,512 (6,015)
Changes in noncurrent liabilities (6,950) 60
- -------------------------------------------------------------------------------
Net cash flows from operating activities 116,165 125,135
- -------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt due to VUHI - 61,900
Additional capital contribution - 25,000
Requirements for:
Dividends to parent (49,542) (52,104)
Retirement of long-term debt, including
premiums paid (450) (68,438)
Redemption of preferred stock (116) (116)
Dividends on preferred stock (13) (23)
Net change in short-term borrowings,
including from VUHI 86,751 44,340
Other activity - (1,744)
- -------------------------------------------------------------------------------
Net cash flows from financing activities 36,630 8,815
- -------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Requirements for:
Capital expenditures (155,814) (132,420)
Other investments 1,121 -
- -------------------------------------------------------------------------------
Net cash flows from investing activities (154,693) (132,420)
- -------------------------------------------------------------------------------
Net increase (decrease) in cash & cash equivalents (1,898) 1,530
Cash & cash equivalents at beginning of period 3,675 2,145
- -------------------------------------------------------------------------------
Cash & cash equivalents at end of period $ 1,777 $ 3,675
===============================================================================
Cash paid during the year for:
Income taxes $ 26,486 $ 30,595
Interest 24,422 24,512
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
STATEMENTS COMMON SHAREHOLDER'S EQUITY
(In thousands)
Common Retained
Stock Earnings Total
- -------------------------------------------------------------------------------
Balance at January 1, 2003 $ 103,258 $ 270,181 $ 373,439
===============================================================================
Net income & comprehensive income 48,857 48,857
Common stock:
Additional capital contribution 25,000 25,000
Dividends to parent (52,104) (52,104)
Preferred stock dividends (23) (23)
- -------------------------------------------------------------------------------
Balance at December 31, 2003 $ 128,258 $ 266,911 $ 395,169
===============================================================================
Net income & comprehensive income 48,579 48,579
Common stock:
Other 5 5
Dividends to parent (49,542) (49,542)
Preferred stock dividends (13) (13)
- -------------------------------------------------------------------------------
Balance at December 31, 2004 $ 128,263 $ 265,935 $ 394,198
===============================================================================
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO THE FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana
corporation, provides energy delivery services to approximately 136,000 electric
customers and approximately 110,000 gas customers located near Evansville in
southwestern Indiana. SIGECO also owns and operates electric generation to serve
its electric customers and optimizes those assets in the wholesale power market.
SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc.
(VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation
(Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana,
Inc. Vectren is an energy and applied technology holding company headquartered
in Evansville, Indiana.
2. Summary of Significant Accounting Policies
A. Cash & Cash Equivalents
All highly liquid investments with an original maturity of three months or less
at the date of purchase are considered cash equivalents.
B. Inventories
Inventories consist of the following:
At December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Materials & supplies $ 19,801 $ 17,304
Fuel (coal and oil) for electric generation 8,762 10,680
Gas in storage - at LIFO cost 7,728 8,599
Emission allowances 308 631
- -----------------------------------------------------------------------------
Total inventories $ 36,599 $ 37,214
=============================================================================
Based on the average cost of gas purchased during December, the cost of
replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31,
2004, and 2003, by approximately $30.4 million and $30.1 million, respectively.
All other inventories are carried at average cost.
C. Utility Plant & Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation of
utility property is provided using the straight-line method over the estimated
service lives of the depreciable assets.
The original cost of utility plant, together with depreciation rates expressed
as a percentage of original cost, follows:
At & For the Year Ended December 31,
- ----------------------------------------------------------------------------------------------
(In thousands) 2004 2003
- ----------------------------------------------------------------------------------------------
Depreciation Depreciation
Rates as a Rates as a
Percent of Percent of
Original Cost Original Cost Original Cost Original Cost
- ----------------------------------------------------------------------------------------------
Electric utility plant $ 1,458,063 3.6% $ 1,322,367 3.4%
Gas utility plant 175,353 3.0% 170,870 3.0%
Common utility plant 44,126 2.7% 44,290 2.7%
Construction work in progress 127,301 - 122,000 -
- ----------------------------------------------------------------------------------------------
Total original cost $ 1,804,843 $ 1,659,527
==============================================================================================
AFUDC represents the cost of borrowed and equity funds used for construction
purposes and is charged to construction work in progress during the construction
period and is included in Other - net in the Statements of Income. The total
AFUDC capitalized into utility plant and the portion of which was computed on
borrowed and equity funds for all periods reported follows:
Year Ended December 31,
- --------------------------------------------------------------------------
(In thousands) 2004 2003
- --------------------------------------------------------------------------
AFUDC - equity funds $ 1,515 $ 2,863
AFUDC - borrowed funds 1,310 1,904
- --------------------------------------------------------------------------
Total AFUDC capitalized $ 2,825 $ 4,767
==========================================================================
Maintenance and repairs, including the cost of removal of minor items of
property and planned major maintenance projects, are charged to expense as
incurred unless deferral is authorized by a rate order. When property that
represents a retirement unit is replaced or removed, the cost of such property
is charged to Utility plant, with an offsetting charge to Accumulated
depreciation and Regulatory liabilities for the cost of removal.
D. Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the
carrying amount may be impaired. This review is performed in accordance with
SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144). SFAS 144 establishes one accounting model for all impaired
long-lived assets and long-lived assets to be disposed of by sale or otherwise.
SFAS 144 requires the evaluation for impairment involve the comparison of an
asset's carrying value to the estimated future cash flows the asset is expected
to generate over its remaining life. If this evaluation were to conclude that
the carrying value of the asset is impaired, an impairment charge would be
recorded based on the difference between the asset's carrying amount and its
fair value (less costs to sell for assets to be disposed of by sale) as a charge
to operations or discontinued operations.
E. Goodwill
Goodwill arising from business combinations is accounted for in accordance with
SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 142 uses
impairment-only approach to account for the effect of goodwill on the operating
results.
Goodwill is tested for impairment at a reporting unit level at least annually
and that test is performed at the beginning of each year. The impairment review
consists of a comparison of the fair value of a reporting unit to its carrying
amount. If the fair value of a reporting unit is less than its carrying amount,
an impairment loss is recognized in operations. Through December 31, 2004, no
goodwill impairment has been recorded. The Company's goodwill is included in the
Gas Utility Services operating segment.
F. Regulation
SFAS 71
Retail public utility operations affecting Indiana customers are subject to
regulation by the IURC. The Company's accounting policies give recognition to
the rate-making and accounting practices of these agencies and to accounting
principles generally accepted in the United States, including the provisions of
SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS
71). Regulatory assets represent probable future revenues associated with
certain incurred costs, which will be recovered from customers through the
rate-making process. Regulatory liabilities represent probable expenditures by
the Company for removal costs or future reductions in revenues associated with
amounts that are to be credited to customers through the rate-making process.
The Company assesses the recoverability of costs recognized as regulatory assets
and the ability to continue to account for its activities based on the criteria
set forth in SFAS 71. Based on current regulation, the Company believes such
accounting is appropriate. If all or part of the Company's operations cease to
meet the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets.
Regulatory assets consist of the following:
At December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Future amounts recoverable from ratepayers:
Income taxes $ 3,354 $ 9,184
Other 962 858
- -----------------------------------------------------------------------------
4,316 10,042
Amounts deferred for future recovery:
Demand side management programs 25,878 24,888
Other 6,555 5,347
- -----------------------------------------------------------------------------
32,433 30,235
Amounts currently recovered through base rates:
Unamortized debt issue costs 5,105 4,515
Premiums paid to reacquire debt 5,712 5,915
Demand side management programs 2,322 2,746
Rate case expenses 706 -
- -----------------------------------------------------------------------------
13,845 13,176
Amounts currently recovered through authorized
Indiana tracking mechanisms (355) 1,172
- -----------------------------------------------------------------------------
Total regulatory assets $ 50,239 $ 54,625
=============================================================================
Of the $13.8 million currently being recovered through base rates, $13.1 million
is earning a return with a weighted average recovery period of 14.8 years. The
Company has rate orders for deferred costs not yet in rates and therefore
believes that future recovery is probable.
Cost of Removal and SFAS 143
The Company collects an estimated cost of removal of its utility plant through
depreciation rates established by regulatory proceedings. The Company records
amounts expensed in advance of payments as a regulatory liability because the
liability does not meet the threshold of a legal asset retirement obligation
(ARO) as defined by SFAS No. 143, "Accounting for Asset Retirement Obligations"
(SFAS 143). At December 31, 2004, and 2003, such removal costs approximated
$51.4 million and $48.2 million, respectively.
SFAS 143 requires entities to record the fair value of a liability for a legal
ARO in the period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss. To the extent
regulation is involved, such gain or loss may be deferred. The Company adopted
this statement on January 1, 2003. The adoption was not material to the
Company's results of operations.
Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased
Power
All metered gas rates contain a gas cost adjustment clause that allows the
Company to charge for changes in the cost of purchased gas. Metered electric
rates contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel. The net energy cost of
purchased power, subject to an agreed upon benchmark, is also recovered through
regulatory proceedings. The Company records any under-or-over-recovery resulting
from gas and fuel adjustment clauses each month in revenues. A corresponding
asset or liability is recorded until the under-or-over-recovery is billed or
refunded to utility customers. The cost of gas sold is charged to operating
expense as delivered to customers, and the cost of fuel for electric generation
is charged to operating expense when consumed.
G. Revenues
Revenues are recorded as products and services are delivered to customers. To
more closely match revenues and expenses, the Company records revenues for all
gas and electricity delivered to customers but not billed at the end of the
accounting period.
H. Utility Receipts Taxes
A portion of utility receipts taxes are included in rates charged to customers.
Accordingly, the Company records these taxes received as a component of
Operating revenues. Utility receipts taxes paid are recorded as a component of
Taxes other than income taxes.
I. Earnings Per Share
Earnings per share are not presented as SIGECO's common stock is wholly owned by
Vectren Utility Holdings, Inc.
J. Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to
intercompany allocations and income taxes (Note 3) and derivatives (Note 10).
K. Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
3. Transactions with Other Vectren Companies
Support Services and Purchases
Vectren and certain subsidiaries of Vectren provided corporate and general and
administrative services to the Company including legal, technology, finance,
tax, risk management, human resources, and charges for share-based compensation
and for pension and other postretirement benefits not directly charged to
subsidiaries. These costs have been allocated using various allocators,
primarily number of employees, number of customers and/or revenues. Allocations
are based on cost. SIGECO received corporate allocations totaling $45.9 million
and $42.3 million for the years ended December 31, 2004, and 2003, respectively.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates
coal mines from which SIGECO purchases fuel used for electric generation.
Amounts paid for such purchases for the years ended December 31, 2004, and 2003,
totaled $79.0 million and $77.0 million, respectively. Amounts charged by
Vectren Fuels, Inc. are established by supply agreements with the utility.
Retirement Plans and Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that
require accounting as described in SFAS No. 87 "Employers' Accounting for
Pensions" and SFAS No. 106 "Employers' Accounting for Postretirement Benefits
Other Than Pensions," respectively. An allocation of expense is determined by
Vectren's actuaries, comprised of only service cost and interest on that service
cost, by subsidiary based on headcount at each measurement date. These costs are
directly charged to individual subsidiaries. Other components of costs (such as
interest cost and asset returns) are charged to individual subsidiaries through
the corporate allocation process discussed above. Neither plan assets nor the
FAS 87/106 liability is allocated to individual subsidiaries since these assets
and obligations are derived from corporate level decisions. Further, Vectren
satisfies the future funding requirements of plans and the payment of benefits
from general corporate assets. This allocation methodology is consistent with
"multiemployer" benefit accounting as described in SFAS 87 and 106.
For the years ended December 31, 2004 and 2003, periodic pension costs totaling
$2.0 million and $2.4 million, respectively, was directly charged by Vectren to
the Company. For the years ended December 31, 2004 and 2003, other periodic
postretirement benefit costs totaling $0.6 million and $0.5 million,
respectively, was directly charged by Vectren to the Company. As of December 31,
2004 and 2003, $25.9 million and $26.4 million, respectively, is included in
Deferred credits & other liabilities and represents expense directly charged to
the Company that is yet to be funded to Vectren.
Cash Management Arrangements
The Company participates in a centralized cash management program with Vectren,
other wholly owned subsidiaries, and banks which permits funding of checks as
they are presented. See Note 5 regarding long-term and short-term intercompany
borrowing arrangements.
Share-Based Incentive Plans
In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based
Payments" (SFAS 123R) that will require compensation costs related to
share-based payment transactions to be recognized in the financial statements.
With limited exceptions, the amount of compensation cost will be measured based
on the grant-date fair value of the equity or liability instruments issued. In
addition, liability awards will be remeasured each reporting period.
Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. SFAS 123(R) replaces FASB Statement No. 123,
"Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25,
"Accounting for Stock Issued to Employees." The effective date of SFAS 123R for
the Company is July 1, 2005. SFAS 123R provides for multiple transition methods,
and the Company is still evaluating potential methods for adoption. SIGECO does
not have share-based compensation plans separate from Vectren. An insignificant
number of the Company's employees participate in Vectren's share-based
compensation plans. The adoption of this standard is not expected to have any
material effect on the Company's operating results or financial condition.
Guarantees of Parent Company Debt
Vectren's three operating utility companies, SIGECO, Indiana Gas Company, Inc.
(Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of VUHI's
$350 million in short-term credit facilities, of which approximately $308.0
million is outstanding at December 31, 2004, and VUHI's $550 million unsecured
senior notes outstanding at December 31, 2004. The guarantees are full and
unconditional and joint and several, and VUHI has no subsidiaries other than the
subsidiary guarantors.
Income Taxes
Vectren and subsidiary companies file a consolidated federal income tax return.
For financial reporting purposes, SIGECO's current and deferred tax expense is
computed on a separate company basis.
The components of income tax expense and utilization of investment tax credits
follow:
Year Ended December 31,
- ----------------------------------------------------------------------------
(In thousands) 2004 2003
- ----------------------------------------------------------------------------
Current:
Federal $ 11,900 $ 27,440
State 5,137 9,447
- ----------------------------------------------------------------------------
Total current taxes 17,037 36,887
- ----------------------------------------------------------------------------
Deferred:
Federal 14,523 (2,358)
State 1,656 (2,534)
- ----------------------------------------------------------------------------
Total deferred taxes 16,179 (4,892)
- ----------------------------------------------------------------------------
Amortization of investment tax credits (1,242) (1,303)
- ----------------------------------------------------------------------------
Total income tax expense 31,974 30,692
- ----------------------------------------------------------------------------
Less: Income tax expense included
in other - net 121 52
- ----------------------------------------------------------------------------
Total income tax expense in
operating income $ 31,853 $ 30,640
============================================================================
A reconciliation of the federal statutory rate to the effective income tax rate
follows:
Year Ended December 31,
- -------------------------------------------------------------------------------
2004 2003
- -------------------------------------------------------------------------------
Statutory rate 35.0 % 35.0 %
State & local taxes, net of federal benefit 5.5 5.6
Amortization of investment tax credit (1.5) (1.6)
All other - net 0.7 (0.4)
- -------------------------------------------------------------------------------
Effective tax rate 39.7 % 38.6 %
===============================================================================
The liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates. Significant components of the net deferred tax liability
follow:
At December 31,
- -------------------------------------------------------------------------------
(In thousands) 2004 2003
- -------------------------------------------------------------------------------
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences $ 130,421 $ 111,404
Regulatory assets recoverable through future rates 9,115 15,614
Regulatory liabilities to be settled through
future rates (5,762) (6,430)
Employee benefit obligations (11,085) (10,371)
Other - net (772) (266)
- -------------------------------------------------------------------------------
Net noncurrent deferred tax liability 121,917 109,951
- -------------------------------------------------------------------------------
Current deferred tax liability:
Deferred fuel costs - net 1,729 3,691
- -------------------------------------------------------------------------------
Net current deferred tax liability 1,729 3,691
- -------------------------------------------------------------------------------
Net deferred tax liability $ 123,646 $ 113,642
===============================================================================
At December 31, 2004 and 2003, investment tax credits totaling $10.7 million and
$11.9 million, respectively, are included in Deferred credits and other
liabilities. These investment tax credits are amortized over the lives of the
related investments. The Company has no tax credit carryforwards at December 31,
2004.
4. Transactions with Vectren Affiliates
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas
and related services to SIGECO, Indiana Gas, the Ohio operations, Citizens Gas
and others. ProLiance's primary business is optimizing the gas portfolios of
utilities and providing services to large end use customers.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
years ended December 31, 2004, and 2003, totaled $79.1 million and $72.8
million, respectively. Amounts owed to ProLiance at December 31, 2004, and 2003,
for those purchases were $11.3 million and $8.3 million, respectively, and are
included in Accounts payable to affiliated companies in the Balance Sheets.
Amounts charged by ProLiance for gas supply services are established by supply
agreements with the utility.
Other Affiliate Transactions
Vectren has ownership interests in other affiliated companies accounted for
using the equity method of accounting that perform underground construction and
repair, facilities locating, and meter reading services to the Company. For the
years ended December 31, 2004, and 2003, fees for these services and
construction-related expenditures paid by the Company to Vectren affiliates
totaled less than $0.1 million and $0.3 million, respectively. Amounts charged
by these affiliates are market based. Amounts owed to unconsolidated affiliates
other than ProLiance totaled less than $0.1 million at December 31, 2004, and
2003, respectively.
5. Borrowing Arrangements & Other Financing Transactions
Short-Term Borrowings
SIGECO mainly relies on the short-term borrowing arrangements of VUHI for its
short-term working capital needs. Borrowings, including third party borrowings,
outstanding at December 31, 2004 and 2003, were $170.5 million and $83.8
million, respectively. The intercompany credit line is limited by VUHI's
available capacity, which is $42 million at December 31, 2004. The line is
subject to the same terms and conditions as VUHI's commercial paper program.
Short-term borrowings bear interest at VUHI's weighted average daily cost of
short-term funds. Additionally, at December 31, 2004, the Company has
approximately $5 million of short-term borrowing capacity with third parties to
supplement its intercompany borrowing arrangements, of which $4.6 million is
available. See the table below for interest rates and outstanding balances:
Year ended December 31,
- ------------------------------------------------------------------------------
2004 2003
- ------------------------------------------------------------------------------
Weighted average total outstanding during
the year payable to VUHI (in thousands) $ 111,756 $ 41,456
Weighted average total outstanding during
the year payable to third parties (in thousands $ 580 $ 928
Weighted average interest rates during the year:
VUHI 1.69% 1.31%
Bank loans 2.19% 1.86%
Long-Term Debt
Senior unsecured obligations and first mortgage bonds outstanding and classified
as long-term follow:
At December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Senior Unsecured Notes Payable to VUHI:
2011, 6.625% $ 86,584 $ 86,584
2018, 5.75% 61,900 61,900
- -----------------------------------------------------------------------------
Total long-term debt payable to VUHI $ 148,484 $ 148,484
=============================================================================
First Mortgage Bonds Payable to Third Parties:
2016, 1986 Series, 8.875% $ 13,000 $ 13,000
2023, Series B, adjustable rate presently
2.08%, tax exempt, auction rate mode,
weighted average for 2004: 4.44% 22,550 22,800
2029, 1999 Senior Notes, 6.72% 80,000 80,000
2015, 1985 Pollution Control Series A,
adjustable rate presently 2.03%, tax
exempt, weighted average for 2004: 3.09% 9,775 9,975
2025, 1998 Pollution Control Series A,
adjustable rate presently 4.75%, tax
exempt, next rate adjustment: 2006 31,500 31,500
2024, 2000 Environmental Improvement
Series A, 4.65%, tax exempt 22,500 22,500
- -----------------------------------------------------------------------------
Total first mortgage bonds 179,325 179,775
- -----------------------------------------------------------------------------
Senior Unsecured Bonds Payable to Third Parties:
2020, 1998 Pollution Control Series B,
4.50%, tax exempt 4,640 4,640
2030, 1998 Pollution Control Series B, 5.00%,
tax exempt 22,000 22,000
2030, 1998 Pollution Control Series C,
adjustable rate presently 5.00%, tax
exempt, next rate adjustment: 2006 22,200 22,200
- -----------------------------------------------------------------------------
Total senior unsecured bonds 48,840 48,840
- -----------------------------------------------------------------------------
Total long-term debt outstanding payable to
third parties 228,165 228,615
Long-term debt subject to tender - (9,975)
Unamortized debt premium & discount &
other - net (2,137) (2,310)
- -----------------------------------------------------------------------------
Long-term debt payable to third parties - net $ 226,028 $ 216,330
=============================================================================
Issuance Payable to VUHI in 2003
In 2003, the Company issued $61.9 million of long-term debt payable to VUHI. The
note has terms identical to the terms of notes issued by VUHI in July 2003
through a public offering. Those notes have an interest rate of 5.75% priced at
99.177% to yield 5.80% to maturity and are due August 2018. They have no sinking
fund requirements, and interest payments are due semi-annually. The notes may be
called by VUHI, in whole or in part, at any time for an amount equal to accrued
and unpaid interest, plus the greater of 100% of the principal amount or the sum
of the present values of the remaining payments of principal and interest,
discounted to the redemption date on a semi-annual basis at the Treasury Rate,
as defined in VUHI's indenture, plus 25 basis points. At present, VUHI has no
intent to call the notes; therefore the notes are classified as long term on the
accompanying Balance Sheets.
Debt Call
During 2003, the Company called two first mortgage bonds. The first bond had a
principal amount of $45.0 million, an interest rate of 7.60%, was originally due
in 2023, and was redeemed at 103.745% of its stated principal amount. The second
bond had a principal amount of $20.0 million, an interest rate of 7.625%, was
originally due in 2025, and was redeemed at 103.763% of the stated principal
amount. Pursuant to regulatory authority, the premiums paid to retire the net
carrying value of these notes totaling $2.4 million were deferred in Regulatory
assets. The proceeds to fund the early redemption were received from VUHI in the
form of new long-term debt discussed above and $25 million in additional equity.
To generate the initial proceeds to fund these transactions, in July 2003, VUHI
completed a public offering of long-term debt netting proceeds of approximately
$203 million, and, in August 2003, Vectren completed a public offering of common
stock netting proceeds of approximately $163 million.
Other Financing Transactions
During 2004, the Company remarketed two first mortgage bonds. The remarketing
effort converted $32.8 million of outstanding fixed rate debt into variable rate
debt where interest rates reset weekly. One bond, due in 2023, had a principal
amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015,
had a principal amount of $10.0 million and an interest rate of 4.3%. These
bonds are classified in Long-term debt.
During 2003, the Company re-marketed $22.5 million of first mortgage bonds
subject to interest rate exposure on a long term basis. The $22.5 million of
mortgage bonds were remarketed through 2024 at a 4.65% fixed interest rate.
Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is one
percent of the greatest amount of bonds outstanding under the Mortgage
Indenture. This requirement may be satisfied by certification to the Trustee of
unfunded property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2005 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2005 is excluded from
Current liabilities in the Balance Sheets. At December 31, 2004, $563.9 million
of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture.
There are no maturities and/or sinking fund requirements on long-term debt
during the five years following 2004.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. The put or call provisions are not
triggered by specific events, but are based upon dates stated in the note
agreements, such as when notes are re-marketed. Debt which may be put to the
Company during the years following 2004 (in millions) is zero in 2005, 2006,
2007, and 2008, $80.0 in 2009 and zero thereafter. Debt that may be put to the
Company within one year is classified as Long-term debt subject to tender in
current liabilities.
Covenants
Both long-term and short-term borrowing arrangements contain customary default
provisions; restrictions on liens, sale leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2004, the Company was in
compliance with all financial covenants.
6. Cumulative Preferred Stock
Redeemable, Special
This series of redeemable preferred stock has a dividend rate of 8.50% and in
the event of involuntary liquidation the amount payable is $100 per share, plus
accrued dividends. This series may be redeemed at $100 per share, plus accrued
dividends on any of its dividend payment dates, and is also callable at the
Company's option at a rate of 1,160 shares per year. As of December 31, 2004,
and 2003, there were 1,177 shares and 2,277 shares outstanding, respectively.
7. Commitments & Contingencies
Commitments
Firm purchase commitments for commodities total $3.7 million in 2005. Firm
purchase commitment for utility and non-utility plant total $13.2 million.
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 8 regarding
environmental matters.
8. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Company has taken steps to comply with Indiana's State Implementation Plan
(SIP) of the Clean Air Act (the Act). These steps include installing Selective
Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley),
Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and
2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water
using ammonia in a chemical reaction. This technology is known to currently be
the most effective method of reducing nitrogen oxide (NOx) emissions where high
removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months, an 8% return on
its weighted capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances, related to the clean coal technology once the facility
is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated
construction cost is consistent with amounts approved in the IURC's orders.
Through December 31, 2004, $238 million has been expended, and three of the four
SCR's are operational. Once all equipment is installed and operational, related
annual operating expenses, including depreciation expense, are estimated to be
between $24 million and $27 million. The Company is recovering the operational
costs associated with the SCR's and related technology. The 8% return on capital
investment approximates the return authorized in the Company's last electric
rate case in 1995 and includes a return on equity.
The Company has achieved timely compliance through the reduction of the
Company's overall NOx emissions to levels compliant with Indiana's NOx emissions
budget allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
During 2003, the U.S. District Court for the Southern District of Indiana
entered a consent decree among SIGECO, the Department of Justice (DOJ), and the
USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO.
The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley
Generating Station for (1) making modifications to generating station without
obtaining required permits, (2) making major modifications to the generating
station without installing the best available emission control technology, and
(3) failing to notify the USEPA of the modifications.
Under the terms of the agreement, the DOJ and USEPA agreed to drop all
challenges of past maintenance and repair activities at the Culley Generating
Station. In reaching the agreement, SIGECO did not admit to any allegations in
the government's complaint, and SIGECO continues to believe that it acted in
accordance with applicable regulations and conducted only routine maintenance on
the units. SIGECO entered into this agreement to further its continued
commitment to improve air quality and avoid the cost and uncertainties of
litigation.
Under the agreement, SIGECO committed to
o either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31, 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June 30, 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company notified the USEPA of its intention to shut down Culley Unit 1
effective December 31, 2006. The Company does not believe that implementation of
the settlement will have a material effect to its results from operations or
financial condition. The $600,000 civil penalty was accrued during 2003 and is
reflected in Other-net.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested
with the most recent correspondence provided on March 26, 2001.
Manufactured Gas Plants
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to
the IDEM the results of preliminary site investigations conducted in the
mid-1990's. These site investigations confirmed that based upon the conditions
known at the time, the sites posed no risk to human health or the environment.
Follow up reviews have been initiated by the Company to confirm that the sites
continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. That renewal was approved
by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory
judgment action against its insurance carriers seeking a judgment finding its
carriers liable under the policies for coverage of further investigation and any
necessary remediation costs that SIGECO may accrue under the VRP program. The
total investigative costs, and if necessary, costs of remediation at the four
SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot
be determined at this time.
9. Rate & Regulatory Matters
Gas Base Rate Settlements
On June 30, 2004, the IURC approved a $5.7 million base rate increase for
SIGECO's gas distribution business. The new rate designs include a larger
service charge, which is intended to address to some extent earnings volatility
related to weather. The base rate change in SIGECO's service territory was
implemented on July 1, 2004, resulting in additional 2004 revenues of $2.5
million.
The order also permits SIGECO to recover the on-going costs to comply with the
Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker
provides for the recovery of incremental non-capital dollars, capped at $750,000
the first year and $500,000 thereafter. Any costs incurred in excess of these
annual caps are to be deferred for future recovery.
10. Derivatives & Other Financial Instruments
Accounting Policy for Derivatives
The Company executes derivative contracts in the normal course of operations
while buying and selling commodities to be used in operations, optimizing its
generation assets, and managing risk. The Company accounts for its derivative
contracts in accordance with SFAS 133, "Accounting for Derivatives" and its
related amendments and interpretations. In most cases, SFAS 133 requires a
derivative to be recorded on the balance sheet as an asset or liability measured
at its market value and that a change in the derivative's market value be
recognized currently in earnings unless specific hedge criteria are met.
When an energy contract that is a derivative is designated and documented as a
normal purchase or normal sale, it is exempted from mark-to-market accounting.
Otherwise, energy contracts and financial contracts that are derivatives are
recorded at market value as current or noncurrent assets or liabilities
depending on their value and on when the contracts are expected to be settled.
The offset resulting from carrying the derivative at fair value on the balance
sheet is charged to earnings unless it qualifies as a hedge or is subject to
SFAS 71. When hedge accounting is appropriate, the Company assesses and
documents hedging relationships between the derivative contract and underlying
risks as well as its risk management objectives and anticipated effectiveness.
When the hedging relationship is highly effective, derivatives are designated as
hedges. The market value of the effective portion of the hedge is marked to
market in accumulated other comprehensive income for cash flow hedges or as an
adjustment to the underlying's basis for fair value hedges. The ineffective
portion of hedging arrangements is marked-to-market through earnings. The offset
to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or
liability. Market value for derivative contracts is determined using quoted
market prices from independent sources. Following is a more detailed discussion
of the Company's use of mark-to-market accounting related to asset optimization
and natural gas procurement.
Asset Optimization
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of the
margin from these activities is generated from contracts that are integrated
with portfolio requirements around power supply and delivery and are short-term
purchase and sale transactions that expose the Company to limited market risk.
Contracts with counter-parties subject to master netting arrangements are
presented net in the Consolidated Balance Sheets. Asset optimization contracts
are recorded at market value.
Asset optimization contracts recorded at market value at December 31, 2004,
totaled $2.5 million of Prepayments & other current assets and $3.1 million of
Accrued liabilities, compared to $2.4 million of Prepayments & other current
assets and $2.8 million of Accrued liabilities at December 31, 2003.
The proceeds received and paid upon settlement of both purchase and sale
contracts along with changes in market value of open contracts are recorded in
Electric utility revenues. Net revenues from asset optimization activities
totaled $23.8 million in 2004 and $26.5 million in 2003.
Natural Gas Procurement Activity
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electricity for retail customers due
to current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms. Although the Company's regulated operations are
exposed to limited commodity price risk, volatile natural gas prices can result
in higher working capital requirements, increased expenses including
unrecoverable interest costs, uncollectible accounts expense, and unaccounted
for gas, and some level of price- sensitive reduction in volumes sold. The
Company mitigates these risks by executing derivative contracts that manage the
price of forecasted natural gas purchases. These contracts are subject to
regulation which allows for reasonable and prudent hedging costs to be recovered
through rates. When regulation is involved, SFAS 71 controls when the offset to
mark-to-market accounting is recognized in earnings. At December 31, 2004 and
2003, the market values of these contracts were not significant.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial
instruments follow:
At December 31,
- --------------------------------------------------------------------------------
2004 2003
---------------------- ---------------------
Carrying Est. Carrying Est.
(In thousands) Amount Fair Value Amount Fair Value
- ---------------------------------- ---------------------- ---------------------
Long term debt $ 228,165 $ 240,294 $ 228,615 $ 239,407
Long term debt payable to VUHI 148,484 159,519 148,484 159,927
Short-term borrowings 339 339 830 830
Short-term borrowings from VUHI 170,171 170,171 82,929 82,929
Certain methods and assumptions must be used to estimate the fair value of
financial instruments. The fair value of the Company's long-term debt was
estimated based on the quoted market prices for the same or similar issues or on
the current rates offered to the Company for instruments with similar
characteristics. Because of the maturity dates and variable interest rates of
short-term borrowings, its carrying amount approximates its fair value.
Under current regulatory treatment, call premiums on reacquisition of long-term
debt are generally recovered in customer rates over the life of the refunding
issue or over a 15-year period. Accordingly, any reacquisition would not be
expected to have a material effect on the Company's results of operations.
11. Additional Operational & Balance Sheet Information
Other - net in the Statements of Income consists of the following:
Year ended December 31,
- ------------------------------------------------------------------------------
(In thousands) 2004 2003
- ------------------------------------------------------------------------------
AFUDC $ 2,825 $ 4,767
Other income 675 1,699
Other expense (355) (1,418)
- ------------------------------------------------------------------------------
Total other - net $ 3,145 $ 5,048
==============================================================================
Accrued liabilities in the Balance Sheets consist of the following:
At December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Accrued taxes $ 7,978 $ 15,979
Deferred income taxes 1,729 3,691
Accrued interest 4,458 5,710
Refunds to customers & customer deposits 13,240 5,124
Accrued salaries & other 10,398 8,115
- -----------------------------------------------------------------------------
Total accrued liabilities $ 37,803 $ 38,619
=============================================================================
12. Segment Reporting
The Company has two operating segments: (1) Gas Utility Services and (2)
Electric Utility Services as defined by SFAS 131 "Disclosure About Segments of
an Enterprise and Related Information" (SFAS 131). Gas Utility Services provides
natural gas distribution and transportation services in southwestern Indiana,
including counties surrounding Evansville. Electric Utility Services provides
electricity primarily to southwestern Indiana, and includes the Company's power
generating and marketing operations. For its operations the Company uses after
tax operating income as a measure of profitability, consistent with regulatory
reporting requirements. The Company cross manages its operations as separated
between Energy Delivery, which includes the gas and electric transmission and
distribution functions, and Power Supply, which includes the power generating
and marketing operations. The Company makes decisions on finance and dividends
at the corporate level. Information related to the Company's business segments
is summarized below:
Year Ended December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Revenues
Electric Utility Services $ 371,279 $ 335,694
Gas Utility Services 110,373 102,736
- -----------------------------------------------------------------------------
Total operating revenues $ 481,652 $ 438,430
=============================================================================
Profitability Measure
Operating Income
Electric Utility Services $ 65,697 $ 63,767
Gas Utility Services 5,070 4,856
- -----------------------------------------------------------------------------
Total operating income $ 70,767 $ 68,623
=============================================================================
Amounts Included in Profitability Measures
Depreciation & Amortization
Electric Utility Services $ 53,341 $ 42,627
Gas Utility Services 5,143 5,022
- -----------------------------------------------------------------------------
Total depreciation & amortization $ 58,484 $ 47,649
=============================================================================
Income Taxes
Electric Utility Services $ 30,770 $ 29,808
Gas Utility Services 1,083 832
- --------------------------------------------------- -------------------------
Total income taxes $ 31,853 $ 30,640
=============================================================================
At December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Assets
Electric Utility Services $1,090,130 $ 974,576
Gas Utility Services 161,347 157,146
- -----------------------------------------------------------------------------
Total assets $1,251,477 $1,131,722
=============================================================================
Year Ended December 31,
- -----------------------------------------------------------------------------
(In thousands) 2004 2003
- -----------------------------------------------------------------------------
Capital Expenditures
Electric Utility Services $ 150,586 $ 124,058
Gas Utility Services 5,228 8,362
- -----------------------------------------------------------------------------
Total capital expenditures $ 155,814 $ 132,420
=============================================================================
13. Impact of Recently Issued Accounting Guidance
FIN 46/46-R (Revised in December 2003)
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. In December 2003, the FASB
completed its deliberations of proposed modifications to FIN 46 and decided to
codify both the proposed modifications and other decisions previously issued
through certain FASB Staff Positions into one document that was issued as a
revision to the original Interpretation (FIN 46R). FIN 46R currently applies to
VIE's created after January 31, 2003, and to VIE's in which an enterprise
obtains an interest after that date. For entities created prior to January 31,
2003, FIN 46R is to be adopted no later than the end of the first interim or
annual reporting period ending after March 15, 2004. The Company has neither
created nor obtained an interest in a VIE since January 31, 2003. Adoption of
FIN 46R did not have a material impact on the Company's results of operations or
financial position.
15. Quarterly Financial Data (Unaudited)
Information in any one quarterly period is not indicative of annual results due
to the seasonal variations common to the Company's utility operations.
Summarized quarterly financial data for 2004 and 2003 follows:
- --------------------------------------------------------------------------------
(In thousands) Q1 Q2 Q3 Q4
- --------------------------------------------------------------------------------
2004
Results of Operations:
Operating revenues $136,804 $104,621 $114,622 $125,605
Operating margin 71,673 64,119 77,126 73,633
Operating income 15,309 12,723 22,261 20,474
Net income applicable to
common shareholder 10,040 7,221 16,744 14,561
2003
Results of Operations:
Operating revenues $135,067 $89,600 $106,257 $107,506
Operating margin 68,325 56,685 71,328 66,016
Operating income 17,883 12,781 21,361 16,598
Net income applicable to
common shareholder 13,381 6,050 16,182 13,221
The following discussion and analysis should be read in conjunction with the
financial statements and notes thereto and the annual reports filed on Forms
10-K of both Vectren and VUHI.
Executive Summary of Consolidated Results of Operations
SIGECO generates revenue primarily from the delivery of natural gas and electric
service to its customers. The primary source of cash flow results from the
collection of customer bills and the payment for goods and services procured for
the delivery of gas and electric services. Results are impacted by weather
patterns in its service territory and general economic conditions both in its
service territory as well as nationally.
In 2004, Earnings were $48.6 million as compared to $48.8 million in 2003. The
minor decrease in earnings is due to increased operating expenses, partially
offset by margin growth. The primary expense changes were higher depreciation
expense and maintenance costs. Margin growth results from the recovery of NOx
related environmental expenditures, gas base rate increases implemented in 2004,
and customer growth.
During 2003, the Company initiated a base rate case for gas service territory.
An order was received in July 2004, and on an annual basis, will increase
margins an estimated $5.7 million. During 2004 the rate increase provided
additional margin of $2.5 million. The order also allows for the recovery of
pipeline integrity management costs capped at $750,000 in 2005 and $500,000
thereafter, with any costs greater than those amounts deferred for future
recovery. The Company has sought and received regulatory recovery mechanisms
(trackers) affecting electric margin that provide a return on utility plant
constructed for environmental compliance and that allow for recovery of related
operating expenses. After tax earnings associated with the NOx compliance
trackers totaled $9.0 million in 2004 and $4.7 million in 2003.
Significant Fluctuations
Throughout this discussion, the terms Gas Utility margin and Electric Utility
margin are used. Gas Utility margin and Electric Utility margin could be
considered non-GAAP measures of income. Gas Utility margin is calculated as Gas
utility revenues less the Cost of gas. Electric Utility margin is calculated as
Electric utility revenues less Fuel for electric generation and Purchased
electric energy. These measures exclude Other operating expenses, Depreciation
and amortization, and Taxes other than income taxes, which are included in the
calculation of operating income. The Company believes Gas Utility and Electric
Utility margins are better indicators of relative contribution than revenues
since gas prices and fuel costs can be volatile and are generally collected on a
dollar for dollar basis from customers. Margins should not be considered an
alternative to, or a more meaningful indicator of, operating performance than
operating income or net income as determined in accordance with accounting
principles generally accepted in the United States.
Margin
Margin generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and impacted by weather patterns in the
Company's service territory. Margin generated from sales to large customers
(generally industrial, other contract, and firm wholesale customers) is
primarily impacted by overall economic conditions. Margin is also impacted by
the collection of state mandated taxes, which fluctuate with gas costs, and is
also impacted by some level of price sensitivity in volumes sold. Electric
generating asset optimization activities are primarily affected by market
conditions, the level of excess generating capacity, and electric transmission
availability. Following is a discussion and analysis of margin generated from
regulated utility operations.
Electric Utility Margin (Electric Utility Revenues less Fuel for Electric
Generation and Purchased Electric Energy)
Electric Utility margin by revenue type follows:
Year Ended December 31,
- ------------------------------------------------------------------------
(In thousands) 2004 2003
- ------------------------------------------------------------------------
Residential & commercial $ 159,716 $ 141,061
Industrial 62,398 53,533
Municipalities & other 17,424 20,174
- ------------------------------------------------------------------------
Total retail & firm wholesale 239,538 214,768
Asset optimization 14,954 18,277
- ------------------------------------------------------------------------
Total electric utility margin $ 254,492 $ 233,045
========================================================================
Retail & Firm Wholesale Margin
Native load and firm wholesale margin was $239.5 million for the year ended
December 31, 2004. This represents a $24.8 million increase over 2003.
Additional NOx recoveries increased margin $14.6 million in 2004. Cooling
weather for the year was 12% warmer than last year, increasing margin an
estimated $2.0 million. The remaining increase in margin was attributable to
increased small customer usage and increased sales to industrial customers. Due
to the above factors, volumes sold increased 5% to 6.19 GWh for 2004, compared
to 5.90 GWh in 2003.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve native
load and firm wholesale customers. The Company markets this unutilized capacity
to optimize the return on its owned generation assets. Substantially all of the
margin from these activities is generated from contracts that are integrated
with portfolio requirements around power supply and delivery and are short-term
purchase and sale transactions that expose the Company to limited market risk.
Following is a reconciliation of asset optimization activity:
Year Ended December 31,
- ------------------------------------------------------------------------------
(In thousands) 2004 2003
- ------------------------------------------------------------------------------
Beginning of Year Net Asset Optimization Position $ (424) $ (718)
Statement of Income Activity
Mark-to-market gains (losses) recognized (1,399) 654
Realized gains (losses) recognized 16,353 17,623
- ------------------------------------------------------------------------------
Net activity in electric utility margin 14,954 18,277
- ------------------------------------------------------------------------------
Net cash received & other adjustments (15,156) (17,983)
- ------------------------------------------------------------------------------
End of Year Net Asset Optimization Position $ (626) $ (424)
==============================================================================
Net wholesale margins decreased $3.3 million compared to 2003 due to reduced
available capacity. The availability of excess capacity was impacted by
scheduled outages of owned generation, related to the installation of
environmental compliance equipment and an increase in demand by native load
customers due to both weather and increased usage.
Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)
Gas Utility margin and throughput by customer type follows:
Year Ended December 31,
- ------------------------------------------------------------------------
(In thousands) 2004 2003
- ------------------------------------------------------------------------
Residential $ 20,296 $ 18,989
Commercial 5,734 5,367
Contract 4,625 4,024
Other 1,404 929
- ------------------------------------------------------------------------
Total gas utility margin $ 32,059 $ 29,309
========================================================================
Volumes in MMDth:
Sold to residential & commercial customers 11,548 12,495
Sold & transported to contract customers 18,701 19,052
- ------------------------------------------------------------------------
Total throughput 30,249 31,547
========================================================================
Gas utility margins were $32.1 million for the year ended December 31, 2004.
This represents an increase in gas utility margin of $2.8 million compared to
2003. Base rate increases added $2.5 million compared to the prior year. Heating
weather for the year ended December 31, 2004, was 8% warmer than normal and 8%
warmer than the prior year. The estimated unfavorable impact on gas utility
margin caused by weather was approximately $0.8 million compared to 2003. Also
offsetting the effects of weather were increased late and reconnect fees and
customer growth. Gas sold and transported volumes were 4% less in 2004, compared
to the prior year. The decreased throughput was primarily attributable to
weather. The average cost per dekatherm of gas purchased was $6.31 in 2004 and
$5.78 in 2003.
Operating Expenses
Other Operating
Other operating expenses increased $9.1 million for the year ended December 31,
2004, as compared to 2003. NOx-related expenses recovered through rates
increased $2.6 million. Maintenance expenses increased $3.5 million primarily
due to planned turbine maintenance. Bad debt expense increased approximately
$1.0 million due in part to higher gas costs. Year-over-year results were also
affected by higher labor and benefit costs and increased corporate charges for
use of shared assets.
Depreciation & Amortization
For the year ended December 31, 2004, depreciation expense increased $10.8
million compared to 2003. NOx-related depreciation contributed $4.8 million of
the increase. The year-over-year increase also affected by a $3.6 million of
additional depreciation resulting from a true-up of demand side management
amortization to existing regulatory orders recorded during 2004. The remaining
increase is primarily due to normal additions to utility plant. Upgrades
implemented in 2002 and 2003 now included in annual depreciation expense include
a gas-fired peaker unit, customer system upgrades, and other upgrades to
existing transmission and distribution facilities.
Income Taxes
For the year ended December 31, 2004, income taxes were $1.2 million higher than
2003 primarily due to an increased effective rate.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $0.9 million in 2004 compared to 2003.
Almost all of the 2004 increase corresponds with increased collections of
utility receipts taxes due to higher revenues.
Other Income (Expense)
Total other income (expense)-net decreased $1.9 million during 2004 compared to
2003. Lower amounts of AFUDC were recorded in 2004 as NOx expenditures were
placed in service.
Interest Expense
In the second half of 2003, the Company completed permanent financing
transactions in which short term borrowings from VUHI and $65 million of higher
coupon third party debt were replaced with $25 million in equity and $61.9 in
long-term debt payable to VUHI. The changes in interest expense in 2004 compared
2003 reflect the full impact of those transactions.
Other Operating Matters
MISO
The FERC approved the Midwest Independent System Operator (MISO) as the nation's
first regional transmission organization. Regional transmission organizations
place public utility transmission facilities in a region under common control.
The MISO is committed to reliability, the nondiscriminatory operation of the
bulk power transmission system, and to working with all stakeholders to create
cost-effective and innovative solutions. The Carmel, Indiana, based MISO began
operations in December 2001 and serves the electrical transmission needs of much
of the Midwest. In December 2001, the IURC approved the Company's request for
authority to transfer operational control over its electric transmission
facilities to the MISO. That transfer occurred on February 1, 2002. Pursuant to
an order from the IURC, certain MISO costs have been deferred for future
recovery.
During 2004, SIGECO together with three other Indiana electric utilities filed a
proceeding with the IURC seeking to recover the anticipated costs associated
with MISO's implementation of the "Day 2 energy market" on April 1, 2005. A
hearing considering this request occurred in February, 2005.
As a result of MISO's operational control over much of the Midwestern electric
transmission grid, including SIGECO's transmission facilities, SIGECO's
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the nature of
MISO's policies regarding use of transmission facilities, as well as ongoing
FERC initiatives and uncertainties around the "Day 2 energy market" operations,
it is difficult to predict near term operational impacts. However, as stated
above, it is believed that MISO's regional operation of the transmission system
will ultimately lead to reliability improvements.
The potential need to expend capital for improvements to the transmission
system, both to SIGECO's facilities as well as to those facilities of adjacent
utilities, over the next several years will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
SELECTED ELECTRIC OPERATING STATISTICS:
- ------------------------------------------------------------------------------
For the Year Ended
December 31,
------------------------------
2004 2003
- ------------------------------------------------------------------------------
OPERATING REVENUES (In thousands):
Residential $ 119,753 $ 105,381
Commercial 92,867 82,268
Industrial 107,568 92,746
Misc. Revenue 3,694 7,185
------------------------------
Total System 323,882 287,580
------------------------------
Municipals 23,561 21,534
Other Wholesale 23,836 26,580
------------------------------
$ 371,279 $ 335,694
==============================
MARGIN (In thousands):
Residential $ 93,459 $ 81,950
Commercial 66,257 59,110
Industrial 62,398 53,533
Misc. Revenue 3,563 7,060
------------------------------
Total System 225,677 201,653
------------------------------
Municipals 13,861 13,115
Other Wholesale 14,954 18,277
------------------------------
$ 254,492 $ 233,045
==============================
ELECTRIC SALES (In MWh):
Residential 1,501,707 1,441,706
Commercial 1,501,513 1,422,127
Industrial 2,543,534 2,416,885
Misc. Sales 13,481 17,210
------------------------------
Total System 5,560,235 5,297,928
------------------------------
Municipals 625,925 600,924
Other Wholesale 3,526,005 4,305,190
------------------------------
9,712,165 10,204,042
==============================
YEAR END CUSTOMERS:
Residential 118,998 117,868
Commercial 17,096 17,054
Industrial 152 155
All others 21 21
------------------------------
136,267 135,098
==============================
WEATHER AS A % OF NORMAL:
Cooling Degree Days 90% 80%
SELECTED GAS OPERATING STATISTICS:
- ------------------------------------------------------------------------------
For the Year Ended
December 31,
-----------------------------
2004 2003
- ------------------------------------------------------------------------------
OPERATING REVENUES (In thousands):
Residential $ 71,713 $ 67,846
Commercial 29,933 28,468
Contract 7,361 5,545
Misc. Revenue 1,366 877
-----------------------------
$110,373 $102,736
=============================
MARGIN (In thousands):
Residential $ 20,296 $ 18,989
Commercial 5,734 5,367
Contract 4,625 4,024
Misc. Revenue 1,404 930
-----------------------------
$ 32,059 $ 29,310
=============================
GAS SOLD & TRANSPORTED (In MDth):
Residential 7,938 8,455
Commercial 3,610 4,040
Contract 18,701 19,052
-----------------------------
30,249 31,547
=============================
YEAR END CUSTOMERS:
Residential 101,611 101,204
Commercial 10,214 10,115
Contract 157 159
-----------------------------
111,982 111,478
=============================
WEATHER AS A % OF NORMAL:
Heating Degree Days 92% 98%