UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended March 31, 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 file number: 1-15467
VECTREN CORPORATION
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(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of incorporation (IRS Employer
or organization) Identification No.)
20 N.W. 4th Street, Evansville, Indiana, 47708
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(Address of principal executive offices)
(Zip Code)
812-491-4000
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has 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 registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X| No __
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes |X| No __
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock- Without Par Value 68,077,722 May 1, 2003
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Class Number of Shares Date
Table of Contents
Item Page
Number Number
PART I. FINANCIAL INFORMATION
1 Financial Statements (Unaudited)
Vectren Corporation and Subsidiary Companies
Consolidated Condensed Balance Sheets 1-2
Consolidated Condensed Statements of Income 3
Consolidated Condensed Statements of Cash Flows 4
Notes to Unaudited Consolidated Condensed
Financial Statements 5-14
2 Management's Discussion and Analysis of Results
of Operations and Financial Condition 15-31
3 Quantitative and Qualitative Disclosures About
Market Risk 31
4 Controls and Procedures 31-32
PART II. OTHER INFORMATION
1 Legal Proceedings 32
6 Exhibits and Reports on Form 8-K 32
Signatures 33
Certifications 34-36
Definitions
AFUDC: allowance for funds used MMBTU: millions of British thermal units
during construction
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh / GWh: megawatt hours / millions 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 PUCO: Public Utilities Commission of Ohio
Environmental Management
IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting
Commission Standards
MCF / BCF: millions / billions USEPA: United States Environmental
of cubic feet Protection Agency
MDth / MMDth: thousands /millions Throughput: combined gas sales and gas
of dekatherms transportation volumes
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
March 31, December 31,
2003 2002
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ASSETS
Current Assets
Cash & cash equivalents $ 28.6 $ 25.1
Accounts receivable-less reserves of
$4.2 & $5.5, respectively 207.8 154.4
Accrued unbilled revenues 82.8 116.1
Inventories 44.2 62.8
Recoverable fuel & natural gas costs 11.9 22.1
Prepayments & other current assets 26.2 93.0
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Total current assets 401.5 473.5
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Utility Plant
Original cost 3,085.9 3,037.1
Less: accumulated depreciation &
amortization 1,412.2 1,389.0
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Net utility plant 1,673.7 1,648.1
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Investments in unconsolidated affiliates 179.0 153.3
Other investments 117.3 124.3
Non-utility property-net 218.3 228.0
Goodwill-net 202.2 202.2
Regulatory assets 78.6 75.2
Other assets 24.0 21.9
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TOTAL ASSETS $ 2,894.6 $ 2,926.5
=============================================================================
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
March 31, December 31,
2003 2002
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LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 52.8 $ 101.7
Accounts payable to affiliated companies 68.4 86.4
Accrued liabilities 150.1 119.9
Short-term borrowings 381.9 399.5
Current maturities of long-term debt 1.0 39.8
Long-term debt subject to tender - 26.6
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Total current liabilities 654.2 773.9
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Long-term Debt-Net of Current Maturities &
Debt Subject to Tender 980.9 954.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes 205.9 195.5
Deferred credits & other liabilities 135.1 130.8
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Total deferred credits & other liabilities 341.0 326.3
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Minority Interest in Subsidiary 1.3 1.9
Commitments & Contingencies (Notes 8, 9)
Cumulative, Redeemable Preferred Stock of
a Subsidiary 0.2 0.3
Common Shareholders' Equity
Common stock (no par value) - issued &
outstanding 68.1 and 67.9, respectively 352.5 350.0
Retained earnings 567.5 530.4
Accumulated other comprehensive income (3.0) (10.5)
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Total common shareholders' equity 917.0 869.9
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TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,894.6 $ 2,926.5
==============================================================================
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited - In millions, except per share data)
Three Months Ended March 31
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2003 2002
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As Restated,
See Note 3
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OPERATING REVENUES
Gas utility $ 509.5 $ 358.1
Electric utility 119.4 126.8
Energy services & other 33.6 145.5
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Total operating revenues 662.5 630.4
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OPERATING EXPENSES
Cost of gas sold 365.1 230.2
Fuel for electric generation 20.8 17.8
Purchased electric energy 40.4 59.7
Cost of energy services & other 25.5 134.8
Other operating 62.6 57.7
Depreciation & amortization 31.4 29.0
Taxes other than income taxes 22.0 18.3
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Total operating expenses 567.8 547.5
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OPERATING INCOME 94.7 82.9
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 8.8 3.1
Other - net (1.1) 2.2
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Total other income 7.7 5.3
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Interest expense 18.9 19.8
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INCOME BEFORE INCOME TAXES 83.5 68.4
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Income taxes 27.7 23.0
Minority interest in & preferred dividend
requirements of subsidiaries 0.1 (0.2)
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NET INCOME $ 55.7 $ 45.6
===============================================================================
AVERAGE COMMON SHARES OUTSTANDING 67.7 67.5
DILUTED COMMON SHARES OUTSTANDING 67.8 67.8
EARNINGS PER SHARE OF COMMON STOCK:
BASIC $ 0.82 $ 0.68
DILUTED $ 0.82 $ 0.67
DIVIDENDS DECLARED PER SHARE OF SHARE
OF COMMON STOCK $ 0.28 $ 0.27
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited - In millions)
Three Months Ended March 31,
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2003 2002
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As Restated,
See Note 3
-------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 55.7 $ 45.6
Adjustments to reconcile net income to cash
from operating activities:
Depreciation & amortization 31.4 29.0
Deferred income taxes & investment tax credits 4.0 3.2
Equity in earnings of unconsolidated affiliates (8.8) (3.1)
Net unrealized loss (gain) on derivative instruments (0.9) 2.9
Pension and postretirement expense 3.5 3.3
Other non-cash charges- net 4.6 0.1
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue (23.9) (10.9)
Inventories 18.6 19.1
Recoverable fuel & natural gas costs 10.2 21.7
Prepayments & other current assets 68.1 87.8
Accounts payable, including to affiliated
companies (66.9) (25.6)
Accrued liabilities 29.0 5.9
Changes in other noncurrent assets (3.5) (1.9)
Changes in other noncurrent liabilities (0.1) (1.0)
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Net cash flows from operating activities 121.0 176.1
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CASH FLOWS REQUIRED FOR FINANCING ACTIVITIES
Proceeds from stock option exercises and other
stock plans 2.2 0.4
Requirements for:
Retirement of long-term debt, including
premiums paid (39.9) (1.3)
Dividends on common stock (18.6) (17.9)
Redemption of preferred stock of subsidiary (0.1) (0.2)
Net change in short-term borrowings (17.6) (121.3)
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Net cash flows required for
financing activities (74.0) (140.3)
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CASH FLOWS REQUIRED FOR INVESTING ACTIVITIES
Proceeds from:
Notes receivable & other collections 9.0 0.6
Unconsolidated affiliate distributions 0.9 0.3
Requirements for:
Capital expenditures, excluding AFUDC-equity (44.2) (40.3)
Unconsolidated affiliate investments (5.2) (3.0)
Notes receivable & other investments (4.0) (0.1)
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Net cash flows required for investing
activities (43.5) (42.5)
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Net increase (decrease) in cash & cash equivalents 3.5 (6.7)
Cash & cash equivalents at beginning of period 25.1 25.0
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Cash & cash equivalents at end of period $ 28.6 $ 18.3
===================================================================================
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Nature of Operations
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999 solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. Both Vectren and VUHI are exempt from registration pursuant to
Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations, owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc., a wholly owned
subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal to the Company's utility operations
and to other parties and generates IRS Code Section 29 investment tax credits
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading services. Broadband invests in broadband communication services
such as analog and digital cable television, high-speed Internet and data
services, and advanced local and long distance phone services. In addition, the
nonregulated group has other businesses that provide utility services, municipal
broadband consulting, and retail products and services and that invest in
energy-related opportunities, real estate and leveraged leases.
2. Basis of Presentation
The interim consolidated condensed financial statements included in this report
have been prepared by the Company, without audit, as provided in the rules and
regulations of the Securities and Exchange Commission. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with accounting principles generally accepted in the United States
have been omitted as provided in such rules and regulations. The Company
believes that the information in this report reflects all adjustments necessary
to fairly state the results of the interim periods reported. These consolidated
condensed financial statements and related notes should be read in conjunction
with the Company's audited annual consolidated financial statements for the year
ended December 31, 2002, filed on Form 10-K. Because of the seasonal nature of
the Company's utility operations, the results shown on a quarterly basis are not
necessarily indicative of annual results.
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 statements
and the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from those estimates.
3. Restatement of Previously Reported Information
Subsequent to the issuance of the 2002 quarterly financial statements,
management determined that previously issued financial statements should be
restated. As a result, the Company has restated its financial statements for the
three months ended March 31, 2002 for various reconciliation errors and other
errors related primarily to the recording of estimates. These errors were not
significant, either individually or in the aggregate, and reduced previously
reported earnings by approximately $68,000 after tax. The restatement also
reduced previously reported energy services and other revenues and cost of
energy services and other by $5.8 million, reflecting the adoption of EITF Issue
No. 99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent."
Following is a summary of the effects of the restatement on previously reported
results of operations for the three months ended March 31, 2002.
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OPERATING REVENUES As reported Adjustments As Restated
Gas utility $ 357.1 $ 1.0 $ 358.1
Electric utility 126.8 - 126.8
Energy services & other 151.3 (5.8) 145.5
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Total operating revenues 635.2 (4.8) 630.4
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OPERATING EXPENSES
Cost of gas sold 230.0 0.2 230.2
Fuel for electric generation 17.8 - 17.8
Purchased electric energy 59.8 (0.1) 59.7
Cost of energy services & other 139.4 (4.6) 134.8
Other operating 56.6 1.1 57.7
Depreciation & amortization 29.1 (0.1) 29.0
Taxes other than income taxes 18.3 - 18.3
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Total operating expenses 551.0 (3.5) 547.5
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OPERATING INCOME 84.2 (1.3) 82.9
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 2.3 0.8 3.1
Other - net 1.4 0.8 2.2
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Total other income 3.7 1.6 5.3
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Interest expense 19.8 - 19.8
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INCOME BEFORE INCOME TAXES 68.1 0.3 68.4
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Income taxes 22.7 0.3 23.0
Minority interest in and preferred
dividends requirement of subsidiaries (0.2) - (0.2)
- -----------------------------------------------------------------------------------
NET INCOME $ 45.6 $ - $ 45.6
===================================================================================
4. Stock Based Compensation
The Company applies APB Opinion 25, "Accounting for Stock Issued to Employees"
(APB25) and related interpretations when measuring compensation expense for its
stock-based compensation plans.
Stock Option Plans
The exercise price of stock options awarded under the Company's stock option
plans is equal to the fair market value of the underlying common stock on the
date of grant. Accordingly, no compensation expense has been recognized for
stock option plans. In January 2003, 384,500 options to purchase shares of
common stock at an exercise price of $23.19 were issued to management. The grant
vests over three years.
Other Plans
In addition to its stock option plans, the Company also maintains restricted
stock and phantom stock plans for executives and non-employee directors. In
January 2003, 93,000 restricted shares with a fair value per share of $23.19
were issued to management. Those shares vest in 2006. Compensation expense
recognized in the consolidated financial statements associated with these
restricted stock and phantom stock plans for the three months ended March 31,
2003 and 2002 was $0.7 million ($0.4 million after tax) and $0.6 million ($0.4
million after tax), respectively, and is consistent with the amount of expense
that would have been recognized if the Company used the fair value method to
value these awards.
Pro forma Information
Following is the effect on net income and earnings per share as if the fair
value based method had been applied to the Company's stock- based compensation
plans:
Three Months Ended March 31,
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In millions, except per share amounts 2003 2002
- -------------------------------------------------------------------------
Net Income:
As reported $ 55.7 $ 45.6
Add: Stock-based employee included in
reported net income- net of tax 0.4 0.4
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards- net of tax 0.7 0.6
- -------------------------------------------------------------------------
Pro forma $ 55.4 $ 45.4
=========================================================================
Basic Earnings Per Share:
As reported $ 0.82 $ 0.68
Pro forma 0.82 0.68
Diluted Earnings Per Share:
As reported $ 0.82 $ 0.67
Pro forma 0.82 0.67
5. Earnings Per Share
Basic earnings per share is computed by dividing net income available to common
shareholders by the weighted-average number of common shares outstanding for the
period. Diluted earnings per share assumes the conversion of stock options into
common shares and the lifting of restrictions on issued restricted shares using
the treasury stock method to the extent the effect would be dilutive. The
following table illustrates the basic and dilutive earnings per share
calculations for the three months ended March 31, 2003 and 2002:
2003 2002
-------------------------- -------------------------
Per Per
In millions, except Share Share
per share amounts Income Shares Amount Income Shares Amount
- ------------------------------------- ---------- ---------- ----------- -------
Basic EPS $55.7 67.7 $ 0.82 $45.6 67.5 $ 0.68
Effect of dilutive
stock equivalents 0.1 0.3
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Diluted EPS $55.7 67.8 $ 0.82 $45.6 67.8 $ 0.67
================================================================================
For the three months ended March 31, 2003, options to purchase 1,287,562 shares
of common stock at exercise prices ranging from $22.54 to $25.59 were not
included in the computation of dilutive earnings per share because the options'
exercise price was greater than the average market price of a share of common
stock during the period. For the three months ended March 31, 2002, all options
were dilutive.
6. Comprehensive Income
Comprehensive income consists of the following:
Three Months
Ended March 31,
----------------
In millions 2003 2002
- -----------------------------------------------------------------
Net income $ 55.7 $ 45.6
Comprehensive income (loss) of
unconsolidated affiliates - net of tax 7.5 (2.3)
- -----------------------------------------------------------------
Total comprehensive income $ 63.2 $ 43.3
=================================================================
Accumulated other comprehensive income arising from unconsolidated affiliates is
the Company's portion of ProLiance Energy, LLC's and Reliant Services, LLC's
accumulated comprehensive income related to the use of cash flow hedges,
including commodity contracts and interest rate swaps, and the Company's portion
of Haddington Energy Partners, LP's accumulated comprehensive income related to
unrealized gains and losses of "available for sale securities."
7. Transactions with 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 Indiana Gas, the Ohio operations and Citizens Gas and
also began providing services to SIGECO and Vectren Retail, LLC (the Company's
retail gas marketer) in 2002. ProLiance's primary businesses include gas
marketing, gas portfolio optimization, and other portfolio and energy management
services. ProLiance's primary customers are utilities and other large end use
customers. Vectren's ownership percentage of ProLiance is 61%. Governance and
voting rights remain at 50% for each member. Since governance of ProLiance
remains equal between the members, Vectren continues to account for its
investment in ProLiance using the equity method of accounting.
Purchases from ProLiance for resale and for injections into storage for the
three months ended March 31, 2003 and 2002 totaled $265.7 million and $127.8
million, respectively. Amounts owed to ProLiance at March 31, 2003 and December
31, 2002 for those purchases were $56.5 million and $84.6 million, respectively,
and are included in accounts payable to affiliated companies. Amounts charged by
ProLiance for gas supply services are established by supply agreements with each
utility.
8. Commitments & Contingencies
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 9 regarding
environmental matters.
Guarantees
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees may include posted letters of credit, debt and leasing guarantees,
performance guarantees, and energy saving guarantees and may periodically
include the debt of and performance obligations of unconsolidated affiliates.
The Company estimates these guarantees totaled approximately $115 million at
March 31, 2003, including outstanding letters of credit. The Company's most
significant guarantee approximating $60 million represents two-thirds of Energy
Systems Group, LLC's (ESG) surety bonds, performance guarantees, and energy
savings guarantees. The guarantees relate to amounts due to various insurance
companies for surety bonds should ESG default on obligations to complete
construction, pay vendors or subcontractors, or to achieve energy savings
guarantees. Through March 31, 2003, the Company has not been called upon to
satisfy any obligations pursuant to its guarantees. ESG was a two-thirds owned
consolidated subsidiary at March 31, 2003. Subsequent to March 31, 2003, the
Company purchased the remaining interest in ESG for approximately $4 million.
Vectren Corporation also guarantees Vectren Capital Corporations long-term and
short-term debt which totaled $113.0 million and $63.6 million, respectively, at
March 31, 2003.
9. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
The Company has initiated steps toward compliance with the revised regulations.
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 be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. Based on the level of system-wide
emissions reductions required and the control technology utilized to achieve the
reductions, the current estimated clean coal technology construction cost ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through March 31, 2003, $80.8 million has been expended.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was completed on schedule, and
construction of the Warrick 4 and Brown SCRs is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce 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
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit is pending in the U.S. District Court for the
Southern District of Indiana. The USEPA alleges that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleges that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual and
the plant continues to operate while the matter is being decided.
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,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
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 Voluntary Remediation Program. 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 recently been initiated
by the Company to confirm that the sites continue to pose no such risk.
10. Impact of Recently Issued Accounting Guidance
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation 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 upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
The Company records a net cost of removal to its utility plant through normal
depreciation rates. As of March 31, 2003 and December 31, 2002 such removal
costs approximated $380 million of accumulated depreciation as presented in the
condensed consolidated balance sheets based upon the Company's latest
depreciation studies.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
Accounting for Derivative Instruments and Hedging Activities. SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133; (2) in connection with other projects dealing with financial
instruments; and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements, which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. Although management is still evaluating the impact of SFAS 149 on
its financial position and results of operations, the adoption is not expected
to have a material effect.
FASB Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a
guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition. The incremental disclosure
requirements are included in these financial statements in Note 8.
FIN 46
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 and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter of 2003
for variable interest entities in which the Company holds a variable interest
acquired before February 1, 2003. Although management is still evaluating the
impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.
11. Segment Reporting
The Company has four operating segments: 1) Gas Utility Services, (2) Electric
Utility Services, (3) Nonregulated Operations, and (4) Corporate and Other. The
Gas Utility Services segment provides natural gas distribution and
transportation services in nearly two-thirds of Indiana and west central Ohio.
The Electric Utility Services segment includes the operations of SIGECO's
electric transmission and distribution services, which provides electricity
primarily to southwestern Indiana, and SIGECO's power generating and power
marketing operations. The Company collectively refers to its gas and electric
utility services segments as its Regulated Operations. Segments within the
Regulated Operations use operating income as a measure of profitability.
The Nonregulated Operations segment is comprised of various subsidiaries and
affiliates offering and investing in energy marketing and services, coal mining,
utility infrastructure services, and broadband communications among other
energy-related opportunities. The Corporate and Other segment, among other
activities, provides general and administrative support and assets, including
computer hardware and software, to the Company's other operating segments. The
Nonregulated Operations and Corporate and Other segment use net income as a
measure of profitability. The Company makes decisions on finance and dividends
at the corporate level.
March 31, December 31,
In millions 2003 2002
- -----------------------------------------------------------------------------
Identifiable Assets
Gas Utility Services $ 1,479.5 $ 1,570.1
Electric Utility Services 880.4 869.2
- -----------------------------------------------------------------------------
Total Regulated 2,359.9 2,439.3
- -----------------------------------------------------------------------------
Nonregulated Operations 412.4 419.6
Corporate & Other 382.3 393.3
Intersegment Eliminations (260.0) (325.7)
- -----------------------------------------------------------------------------
Total identifiable assets $ 2,894.6 $ 2,926.5
=============================================================================
Three Months
Ended March 31,
--------------------------------
In millions 2003 2002
- -----------------------------------------------------------------------------
Operating Revenues
Gas Utility Services $ 509.5 $ 358.1
Electric Utility Services 119.4 126.8
- -----------------------------------------------------------------------------
Total Regulated 628.9 484.9
- -----------------------------------------------------------------------------
Nonregulated Operations 53.2 159.5
Corporate & Other 6.9 5.7
Intersegment Eliminations (26.5) (19.7)
- -----------------------------------------------------------------------------
Total operating revenues $ 662.5 $ 630.4
=============================================================================
Measure of Profitability
Operating Income
Gas Utility Services $ 69.3 $ 62.1
Electric Utility Services 23.9 16.4
- -----------------------------------------------------------------------------
Total Regulated operating income 93.2 78.5
- -----------------------------------------------------------------------------
Regulated other income (expense)-net (1.1) 2.0
Regulated interest expense (15.5) (15.9)
Regulated income taxes (29.5) (23.4)
- -----------------------------------------------------------------------------
Regulated net income 47.1 41.2
- -----------------------------------------------------------------------------
Nonregulated net income 8.5 4.4
Corporate & other net income 0.1 -
- -----------------------------------------------------------------------------
Net income $ 55.7 $ 45.6
=============================================================================
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999 solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. Both Vectren and VUHI are exempt from registration pursuant to
Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations, owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc., a wholly owned
subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal to the Company's utility operations
and to other parties and generates IRS Code Section 29 investment tax credits
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading services. Broadband invests in broadband communication services
such as analog and digital cable television, high-speed Internet and data
services, and advanced local and long distance phone services. In addition, the
nonregulated group has other businesses that provide utility services, municipal
broadband consulting, and retail products and services and that invest in
energy-related opportunities, real estate, and leveraged leases.
Consolidated Results of Operations
The following discussion and analysis should be read in conjunction with the
unaudited condensed consolidated financial statements and notes thereto.
Subsequent to the issuance of the Company's 2002 quarterly financial statements,
the Company's management determined that previously issued financial statements
should be restated. The restatement had the effect of decreasing net income for
the three months ended March 31, 2002 by $68,000 after tax. Note 3 to the
consolidated condensed financial statements includes a summary of the effects of
the restatement. The Company's results of operations give effect to the
restatement.
Three Months Ended March 31,
- -------------------------------------------------------------------------
In millions, except per share amounts 2003 2002
- -------------------------------------------------------------------------
Net income $ 55.7 $ 45.6
Attributed to:
Utility Group $ 47.3 $ 42.0
Nonregulated Group 8.5 4.4
Corporate & Other Group (0.1) (0.8)
- -------------------------------------------------------------------------
Basic earnings per share $ 0.82 $ 0.68
Attributed to:
Utility Group $ 0.70 $ 0.62
Nonregulated Group 0.13 0.07
Corporate & Other Group (0.01) (0.01)
Net Income
For the three months ended March 31, 2002, net income was $55.7 million, or
$0.82 per share, compared to $45.6 million, or $0.68 per share in 2002. The
$10.1 million increase, or $0.14 per share, is due principally to the effect of
colder weather on gas and electric utility operations and the effect of more
volatile electric and gas commodity prices on power marketing operations and gas
marketing investments. During 2003, the Company has also benefited from
synergies gained by the integration of its two gas marketing operations which
was completed June 2002. These increases were offset somewhat by increased
operating expenses caused by higher gas costs.
Dividends
Dividends declared for the three months ended March 31, 2003 were $0.275 per
share compared to $0.265 per share for the same period in 2002.
Detailed Discussion of Results of Operations
Following is a more detailed discussion of the results of operations of the
Company's Utility Group and Nonregulated Group. The detailed results of
operations for the Utility Group and Nonregulated Group are presented and
analyzed before the reclassification and elimination of certain intersegment
transactions necessary to consolidate those results into the Company's
Consolidated Condensed Statements of Income. The operations of the Corporate and
Other Group are not significant.
Results of Operations of the Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consists of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and components of the
Corporate and Other operating segment. Gas Utility Services provides natural gas
distribution and transportation services in nearly two-thirds of Indiana and
west central Ohio. Electric Utility Services provides electricity primarily to
southwestern Indiana, and includes the Company's power generating and marketing
operations. Corporate and Other Operations provides information technology and
other support services to those utility operations. The results of operations of
the Utility Group before certain intersegment eliminations and reclassifications
for the three months ended March 31, 2003 and 2002 follows.
- ---------------------------------------------------------------------
In millions, except per share amounts 2003 2002
- ---------------------------------------------------------------------
OPERATING REVENUES
Gas revenues $ 509.5 $ 358.1
Electric revenues 119.4 126.8
Other revenues 0.2 0.1
- ---------------------------------------------------------------------
Total operating revenues 629.1 485.0
- ---------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 365.1 230.5
Fuel for electric generation 20.8 17.8
Purchased electric energy 40.4 59.7
Other operating 56.6 51.3
Depreciation & amortization 28.8 26.8
Taxes other than income taxes 21.7 18.1
- ---------------------------------------------------------------------
Total operating expenses 533.4 404.2
- ---------------------------------------------------------------------
OPERATING INCOME 95.7 80.8
OTHER INCOME (EXPENSE) - NET
Equity in losses of unconsolidated
affiliates (0.5) (0.1)
Other - net (1.5) 2.1
- ---------------------------------------------------------------------
Total other income (expense) - net (2.0) 2.0
- ---------------------------------------------------------------------
Interest expense 16.5 17.6
- ---------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 77.2 65.2
- ---------------------------------------------------------------------
Income taxes 29.9 23.2
- ---------------------------------------------------------------------
NET INCOME $ 47.3 $ 42.0
=====================================================================
BASIC EARNINGS PER SHARE $ 0.70 $ 0.62
=====================================================================
The Utility Group contributed net income of $47.3 million, or $0.70 per share,
for the three months ended March 31, 2003 compared to $42.0 million, or $0.62
for the same period in 2002. The increase in net income results primarily from
the effects of colder weather and increased margins in wholesale operations.
These increases were offset somewhat by the effect of higher gas costs which
increased operating expenses, including uncollectible accounts expense.
Significant Fluctuations
Utility Margin
Gas Utility Margin
Gas utility margin by customer type and separated between volumes sold and
transported follows:
Three Months Ended March 31,
- -------------------------------------------------------
In millions 2003 2002
- -------------------------------------------------------
Residential $ 93.9 $ 85.1
Commercial 33.3 24.8
Contract 14.7 16.8
Other 2.5 0.9
- -------------------------------------------------------
Total gas margin $ 144.4 $ 127.6
=======================================================
Volumes in MMDth
Sold 64.0 51.7
Transported 28.1 26.9
- -------------------------------------------------------
Total throughput 92.1 78.6
=======================================================
Gas utility margin for the three months ended March 31, 2003, increased $16.8
million, or 13%, compared to 2002. The increase is primarily due to weather 23%
colder than the prior year and 8% colder than normal. The effects of colder
weather resulted in a 17% increase in total throughput. The total average cost
per dekatherm of gas purchased for the three months ended March 31, 2003, was
$6.53 compared to $4.47 for the same period in 2002.
Electric Utility Margin
Electric utility margin by customer type and non-firm wholesale margin separated
between realized margin and mark-to-market gains and losses follows:
Three Months Ended March 31,
- --------------------------------------------------------------
In millions 2003 2002
- --------------------------------------------------------------
Retail & firm wholesale $ 50.1 $ 48.2
Non-firm wholesale 8.1 1.1
- --------------------------------------------------------------
Total electric margin $ 58.2 $ 49.3
==============================================================
Non-firm wholesale margin:
Realized margin $ 7.2 $ 4.0
Mark-to-market gains (losses) 0.9 (2.9)
Electric utility margin for the three months ended March 31, 2002 increased $8.9
million, or 18%, compared to 2002 primarily due to the effect of price
volatility in the wholesale power market. Periodically, generation capacity is
in excess of that needed to serve retail and firm wholesale customers. The
Company markets this unutilized capacity to optimize the return on its owned
generation assets. The contracts entered into are primarily short-term purchase
and sale transactions that expose the Company to limited market risk. In 2003,
volumes sold into the wholesale market were 1.45 GWh compared to 2.47 GWh in
2002. Volumes purchased from the wholesale market, some of which were utilized
to serve retail and firm wholesale customers, were 1.26 GWh in 2003 compared to
2.34 GWh in 2002. While volumes both sold and purchased in the wholesale market
have decreased during 2003, margins increased $7.0 million compared to 2002 as a
result of increased capacity and price volatility.
The effect of colder weather on electric heating sales was the primary factor
for the $1.9 million increase in electric margin from retail and firm wholesale
customers. As result of the colder weather, volumes sold to retail and firm
wholesale customers increased 2% from 1.40 GWh in 2002 to 1.42 GWh in 2003.
Utility Group Operating Expenses
Other Operating
Other operating expenses increased $5.3 million for the three months ended March
31, 2003 compared to the prior year. The increase results principally from
increased uncollectible accounts expense, uncollectible accounts expense related
to the percent of income payment plan (PIPP) in Ohio, and timing of maintenance
expenditures. Uncollectible accounts and PIPP expense increased by $2.1 million
due primarily to higher gas costs.
Depreciation & Amortization
Depreciation and amortization increased $2.0 million for the three months ended
March 31, 2003 compared to the prior year. The increase results from
depreciation of additions to utility plant.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $3.6 million for the three months ended
March 31, 2003 compared to the prior year. The increase results from higher
utility receipts and excise taxes as a result of higher volumes sold and higher
gas prices.
Utility Group Other Income (Expense) - Net
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates increased $0.4 million for the
three months ended March 31, 2003 compared to the prior year. The increase
results from increased losses incurred by a company that manufactures autoclaved
aerated concrete products from fly ash.
Other- net
Other, net decreased $3.6 million for the three months ended March 31, 2003
compared to the prior year. The decrease results principally from charges taken
against the Company's equity method investment that processes fly ash of
approximately $2.0 million. The remaining decrease results from less AFUDC, and
increased contributions to low-income heating assistance programs.
Utility Group Interest Expense
Interest expense decreased $1.1 million for the three months ended March 31,
2003, when compared to the prior year. The decrease results from lower interest
rates on variable rate debt offset partially by higher outstanding balances. The
increased debt outstanding is due primarily to increased working capital
requirements resulting from the higher gas prices experienced during 2003 and
the funding of certain capital expenditures with short-term borrowings.
Utility Group Income Tax
Federal and state income taxes related to the Utility Group increased $6.7
million for the three months ended March 31, 2003, when compared to the prior
year. The increase results principally from higher pre-tax earnings. The
effective tax rate increased from 35.6% in 2002 to 38.7% in 2003 principally due
to an increase in the Indiana state income tax rate from 4.5 % to 8.5% that was
effective January 1, 2003.
Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
The Company has initiated steps toward compliance with the revised regulations.
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 be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002. Based on the level of system-wide
emissions reductions required and the control technology utilized to achieve the
reductions, the current estimated clean coal technology construction cost ranges
from $240 million to $250 million and is expected to be expended during the
2001-2006 period. Through March 31, 2003, $80.8 million has been expended.
On June 5, 2002, the Company filed a new proceeding to update the NOx project
cost and to obtain approval of a second rider authorizing ongoing recovery of
depreciation and operating costs related to the clean coal technology. After the
equipment is installed and operational, related annual operating expenses,
including depreciation expense, are estimated to be between $24 million and $27
million. Such expenses would commence in 2004 when the technology becomes
operational. On January 3, 2003, the IURC approved a settlement that authorizes
total capital cost investment for this project up to $244 million (excluding
AFUDC) and recovery on those capital costs, as well as the recovery of future
operating costs, including depreciation and purchased emission allowances,
through a rider mechanism. The settlement establishes a fixed return of 8
percent on the capital investment, which approximates the return authorized in
the Company's last electric rate case in 1995.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was completed on schedule, and
construction of the Warrick 4 and Brown SCRs is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce 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
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit is pending in the U.S. District Court for the
Southern District of Indiana. The USEPA alleges that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleges that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair, and replacement
activities at the Culley Generating Station, as allowed under the Act. Because
proper maintenance does not require permits, application of the best available
control technology, notice to the USEPA, or compliance with new source
performance standards, SIGECO believes that the lawsuit is without merit, and
intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA
has voluntarily dismissed a majority of the claims brought in its original
complaint. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order. Trial is currently set to begin July 14, 2003.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual and
the plant continues to operate while the matter is being decided.
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,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
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 Voluntary Remediation Program. 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 recently been initiated
by the Company to confirm that the sites continue to pose no such risk.
Results of Operations of the Nonregulated Group
The Nonregulated Group is comprised of four primary business areas: Energy
Marketing and Services, Coal Mining, Utility Infrastructure Services, and
Broadband. Energy Marketing and Services markets natural gas and provides energy
management services, including energy performance contracting services. Coal
Mining mines and sells coal to the Company's utility operations and to other
parties and generates IRS Code Section 29 investment tax credits relating to the
production of coal-based synthetic fuels. Utility Infrastructure Services
provides underground construction and repair, facilities locating, and meter
reading services. Broadband invests in broadband communication services such as
analog and digital cable television, high-speed Internet and data services, and
advanced local and long distance phone services. In addition, the Nonregulated
Group has other businesses that provide utility services, municipal broadband
consulting, and retail products and services and that invest in energy-related
opportunities, real estate and leveraged leases. The results of operations of
the Nonregulated Group before certain intersegment eliminations and
reclassifications for the three months ended March 31, 2003 and 2002 follows:
In millions, except per share amounts 2003 2002
- ------------------------------------------------------------------------
Energy services & other revenues $ 53.2 $ 159.5
Operating expenses:
Cost of energy services & other revenues 44.7 148.0
Operating expenses 9.1 9.1
- ------------------------------------------------------------------------
Total expenses 53.8 157.1
- ------------------------------------------------------------------------
OPERATING INCOME (LOSS) (0.6) 2.4
Other income:
Equity in earnings of unconsolidated
affiliates 9.3 3.2
Other - net 1.1 1.0
- ------------------------------------------------------------------------
Total other income 10.4 4.2
- ------------------------------------------------------------------------
Interest expense 2.4 2.3
- ------------------------------------------------------------------------
INCOME BEFORE TAXES 7.4 4.3
Income tax (1.2) 0.1
Minority interest in consolidated
subsidiaries 0.1 (0.2)
- ------------------------------------------------------------------------
NET INCOME $ 8.5 $ 4.4
========================================================================
BASIC EARNINGS PER SHARE $ 0.13 $ 0.07
========================================================================
NET INCOME ATTRIBUTED TO:
Energy Marketing & Services $ 8.4 $ 4.6
Coal Mining 2.5 2.0
Utility Infrastructure (1.0) (0.5)
Broadband 0.1 0.1
Other Businesses (1.5) (1.8)
The Nonregulated Group contributed net income of $8.5 million, or $0.13 per
share, for the three months ended March 31, 2003 compared to $4.4 million, or
$0.07 per share, for the same period in 2003. The increase of $4.1 million, or
$0.06 per share, results primarily from increased earnings generated from the
Company's investment in ProLiance Energy, LLC (ProLiance), which is a component
of Energy Marketing and Services.
Energy Marketing & Services
Energy Marketing and Services includes the Company's investment in ProLiance, a
nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke
Utility (Citizens Gas). ProLiance provides natural gas and related services to
Indiana Gas, the Ohio operations and Citizens Gas and also began providing
services to SIGECO and Vectren Retail, LLC (the Company's retail gas marketer)
in 2002. ProLiance's primary businesses include gas marketing, gas portfolio
optimization, and other portfolio and energy management services. ProLiance's
primary customers are utilities and other large end use customers.
ProLiance provides natural gas and related services to Indiana Gas, the Ohio
operations, Citizens Gas, and others and also began providing service to SIGECO
and Vectren Retail, LLC (the Company's retail gas marketer) in 2002. ProLiance's
primary business is optimizing the gas portfolios of utilities and providing
services to large end use customers. In addition, Energy Marketing and Services
includes the operations of Energy Systems Group, LLC (ESG), which provides
energy performance contracting and facility upgrades through its design and
installation of energy-efficient equipment. ESG is a consolidated venture
between the Company and Citizens Gas, with the Company owning two-thirds.
Subsequent to March 31, 2003, the Company purchased the remaining interest in
ESG for approximately $4 million. ESG had no significant impact on the Company's
financial results for the three months ended March 31, 2003 or 2002.
In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP
Energy Services, LLC (SES) with ProLiance was completed. SES provided natural
gas and related services to SIGECO and others prior to the integration. In
exchange for the contribution of SES' net assets, Vectren's allocable share of
ProLiance's profits and losses increased from 52.5% to 61%, consistent with
Vectren's new ownership percentage. Governance and voting rights remain at 50%
for each member. Since governance of ProLiance remains equal between the
members, Vectren continues to account for its investment in ProLiance using the
equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. SES' revenues and expenses were
the primary component of nonregulated revenues and cost of revenues. Therefore,
the integration significantly decreased revenues by $125.3 million and costs of
revenues by $120.1 million in 2003 compared to 2002. The Company's operating
expenses also decreased $2.3 million in 2003 as a result of the integration. The
transfer of net assets was accounted for at book value consistent with joint
venture accounting and did not result in any gain or loss.
Pre-tax income of $14.2 million and $5.4 million was recognized as ProLiance's
contribution to earnings for the three months ended March 31, 2003 and 2002,
respectively. Pre-tax earnings have increased primarily as a result of volatile
natural gas prices, increased operations due in part to the integration of SES'
operations, synergies gained through integration, and the Company's increased
ownership. Earnings recognized from ProLiance are included in equity in earnings
of unconsolidated affiliates.
Coal Mining
Coal Mining provides the mining and sale of coal to the Company's utility
operations and to other third parties through its wholly owned subsidiary
Vectren Fuels, Inc. The group also generates IRS Code Section 29 investment tax
credits relating to the production of coal-based synthetic fuels through its
investment in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon is an
unconsolidated affiliate accounted for using the equity method.
Earnings from Vectren Fuels, Inc. were $0.9 million in 2003 and $1.2 million in
2002. In 2003 compared to 2002, both net income and margins decreased as a
result of lower market prices on third party coal sales and a somewhat lower
yield per ton mined.
The investment in Pace Carbon resulted in losses reflected in equity in earnings
of unconsolidated affiliates totaling $3.5 million and $0.9 million for the
three months ended March 31, 2003 and 2002, respectively. Losses have increased
as a result of increased production of synthetic fuels and higher production
costs. The production of synthetic fuel generates IRS Code Section 29 investment
tax credits that are reflected in income taxes. These credits have also
increased consistent with increased synthetic fuel production. Net income,
including the losses, tax benefits, and tax credits, generated from the
investment in Pace Carbon totaled $1.6 million and $0.8 million for the three
months ended March 31, 2003 and 2002, respectively.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of
utility infrastructure services to the Company and to other gas, water,
electric, and telecommunications companies as well as facilities locating and
meter reading services through its investment in Reliant Services, LLC
(Reliant). Reliant is a 50% owned strategic alliance with an affiliate of
Cinergy Corp. and is accounted for using the equity method of accounting.
Reliant's loss has increased in 2003 primarily due to colder weather delaying
certain construction projects.
Broadband
Broadband invests in broadband communication services such as cable television,
high-speed Internet, and advanced local and long distance phone services. The
Company has an approximate 1% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom) that if converted bring the
Company's ownership interest up to 12%. Utilicom is a provider of bundled
communication services focusing on last mile delivery to residential and
commercial customers. The Company also has a 18.9% equity interest in SIGECOM
Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in
SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater
Evansville, Indiana, area.
The equity investments in Utilicom and Holdings are accounted for using the cost
method of accounting. As a result, for the three months ended March 31, 2003 and
2002, Broadband had no significant impact on the Company's operating results.
Utilicom also plans to provide broadband services to the greater Indianapolis,
Indiana, and Dayton, Ohio, markets. However, the funding of these projects has
been delayed due to the continued difficult environment within the
telecommunication capital markets, which has prevented Utilicom from obtaining
debt financing on terms it considers acceptable. While the existing investors
remain interested in the Indianapolis and Dayton projects, the Company is not
required to make further investments and does not intend to proceed unless
commitments are obtained to fully fund these projects. Franchising agreements
have been extended in both locations.
Other Businesses
The Other Businesses Group includes a variety of wholly owned operations and
investments. The significant activities that affected the nonregulated results
of operations during the three months ended March 31, 2003 compared to 2002 are
the wholly owned operations of Vectren Retail LLC (Vectren Retail).
Vectren Retail provides natural gas and other related products and services
primarily in Ohio, serving customers opting for choice among energy providers.
Vectren Retail began operations in 2001 and continues to incur startup costs.
These start up costs have increased operating expenses approximately $1.1
million during the three months ended March 31, 2003 compared to 2002. These
operations produced margin of approximately $2.0 million on sales of $15.9
million in 2003 compared to margin of $0.2 million on sales of $1.6 million in
2002.
Impact of Recently Issued Accounting Guidance
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation 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 upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
The Company records a net cost of removal to its utility plant through normal
depreciation rates. As of March 31, 2003 and December 31, 2002 such removal
costs approximated $380 million of accumulated depreciation as presented in the
condensed consolidated balance sheets based upon the Company's latest
depreciation studies.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
Accounting for Derivative Instruments and Hedging Activities. SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133; (2) in connection with other projects dealing with financial
instruments; and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements, which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. Although management is still evaluating the impact of SFAS 149 on
its financial position and results of operations, the adoption is not expected
to have a material effect.
Financial Accounting Interpretation (FIN) 45
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a
guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the obligations it has undertaken. The objective of
the initial measurement of that liability is the fair value of the guarantee at
its inception. The initial recognition and measurement provisions are applicable
on a prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition. The incremental disclosure
requirements are included in these financial statements in Note 8.
FIN 46
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 and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies to variable interest
entities and, thus improves comparability between enterprises engaged in similar
activities when those activities are conducted through variable interest
entities. FIN 46 applies to variable interest entities created after January 31,
2003 and to variable interest entities in which an enterprise obtains an
interest after that date. FIN 46 applies to the Company's third quarter for
variable interest entities in which the Company holds a variable interest
acquired before February 1, 2003. Although management is still evaluating the
impact of FIN 46 on its financial position and results of operations, the
adoption is not expected to have a material effect.
Financial Condition
Within Vectren's consolidated group, VUHI funds short-term and long-term
financing needs of the utility group operations, and Vectren Capital Corp (Cap
Corp) funds short-term and long-term financing needs of the nonregulated and
corporate operations. Vectren Corporation guarantees Cap Corp's debt, but does
not guarantee VUHI's debt. Cap Corp's long-term and short-term obligations
outstanding at March 31, 2003 totaled $113.0 million and $63.6 million,
respectively. VUHI's currently outstanding long-term and short-term borrowing
arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and
VEDO. VUHI's long-term and short-term obligations outstanding at March 31, 2003
totaled $350.0 million and $312.6 million, respectively. Additionally, prior to
VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and
therefore, have debt outstanding funded solely by their operations.
Utility operations have historically funded the majority of the Company's common
stock dividends. Nonregulated operations have demonstrated sustained
profitability, and the ability to generate cash flows. These cash flows are
ordinarily reinvested in other nonregulated ventures. In the future,
nonregulated cash flows could be used to fund a small portion of the Company's
dividend requirement.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
March 31, 2003 are A-/Baa1 as rated by Standard and Poor's Ratings Services
(Standard and Poor's) and Moody's Investor's Service (Moody's), respectively.
SIGECO's credit ratings on outstanding senior unsecured debt at December 31,
2002 are BBB+/Baa1. SIGECO's credit ratings on outstanding secured debt at March
31, 2003 are A-/A3. VUHI's commercial paper has a credit rating of A-2/P-2. Cap
Corp's senior unsecured debt is rated BBB+/Baa2. Moody's current outlook is
stable while Standard and Poor's current outlook is negative. The ratings of
Moody's and Standard and Poor's are categorized as investment grade and are
unchanged from December 31, 2002. A security rating is not a recommendation to
buy, sell, or hold securities. The rating is subject to revision or withdrawal
at any time, and each rating should be evaluated independently of any other
rating. Moody's and Standard and Poor's lowest level investment grade rating is
Baa3 and BBB-, respectively.
The Company's consolidated equity capitalization objective is 45-55% of total
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, and seasonal
factors that affect the Company's operation. The Company's equity component was
48% and 46% of total capitalization, including current maturities of long-term
debt and long-term debt subject to tender, at March 31, 2003 and December 31,
2002, respectively.
The Company expects the majority of its capital expenditures, investments, and
debt security redemptions to be provided by internally generated funds. However,
additional permanent financing may be required due to significant capital
expenditures for NOx compliance equipment at SIGECO and plans to further
strengthen the Company's capital structure and the capital structures of VUHI
and its utility subsidiaries. These plans may include the issuance of new equity
and debt and the calling of certain long-term debt at SIGECO and Indiana Gas.
In April 2003, the Company filed with the United States Securities and Exchange
Commission a Form S-3 to issue a maximum of $150 million of new equity
securities and to issue $200 million in debt securities at VUHI. Specific to the
NOx compliance project, the Company is authorized an 8 percent return on its
capital investments through approved rider recovery mechanisms
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary and historical source of liquidity to fund working capital
requirements has been cash generated from operations, which for the three months
ended March 31, 2003 and 2002 was $121.0 million and $176.1 million,
respectively. The decrease of $55.1 million is primarily the result of more
favorable changes in working capital accounts occurring in 2002 due to a return
to lower gas prices in that year, offset by increased earnings before non-cash
charges in 2003.
Financing Cash Flow
Although working capital requirements are generally funded by cash flow from
operations, the Company uses short-term borrowings to supplement working capital
needs when accounts receivable balances are at their highest and gas storage is
refilled. Additionally short-term borrowings are required for capital projects
and investments until they are permanently financed.
Cash flow required for financing activities of $74.0 million for the three
months ended March 31, 2003 includes a decrease in borrowings outstanding of
$57.5 million and increased common stock dividends compared to 2002. In 2002,
higher operating cash flow was used to repay $122.6 million in borrowings.
Financing Transactions
In January, 2003, the Company called the remaining $23.8 million of Indiana Gas'
9.375% private placement notes originally due in 2021. The total amount paid on
redemption was $24.9 million. Pursuant to regulatory authority the premium paid
was deferred as a regulatory asset. Also in January, 2003, other debt of Indiana
Gas totaling $15.0 million was paid as scheduled.
At December 31, 2002, the Company had $26.6 million of adjustable rate senior
unsecured bonds which could, at the election of the bondholder, be tendered to
the Company when interest rates are reset. Such bonds were classified as
long-term debt subject to tender. Subsequent to March 31, 2003, the Company
re-marketed those bonds on a long-term basis and has therefore reclassified them
as long-term debt at March 31, 2003.
Investing Cash Flow
Cash required for investing activities of $43.5 million for the three months
ended March 31, 2003 includes $44.2 million of requirements for capital
expenditures. Investing activities for 2002 were $42.5 million. The increase
occurring in 2003 is principally the result of additional capital expenditures,
principally for the NOx project in 2003, offset by proceeds received from
collections on notes receivable.
Available Sources of Liquidity
At March 31, 2003, the Company has $655.0 million of short-term borrowing
capacity, including $475.0 million for the Utility Group and $180.0 million for
wholly owned Nonregulated Group and corporate operations, of which approximately
$159.2 million is available for Utility Group operations and $113.7 million is
available for wholly owned Nonregulated Group and corporate operations. The
availability of short-term borrowing is reduced by outstanding letters of credit
totaling $2.7 million, collateralizing nonregulated activities. Subsequent to
December 31, 2002, the Company increased its Utility Group capacity $145.0
million to $475.0 million, and subsequent to March 31, 2003 decreased its
Nonregulated Group and corporate capacity to $175.0 million. Effective January
1, 2003, the Company transferred certain assets that primarily support the
regulated operations from other wholly owned subsidiaries to VUHI. This transfer
of assets takes advantage of the greater borrowing capacity available to the
Utility Group and will make the nonregulated and corporate capacity available
for those operations.
Beginning in 2003 the Company began issuing new shares to satisfy dividend
reinvestment plan requirements. During the three months ended March 31, 2003,
new issues from stock plans added additional liquidity of approximately of $1.8
million, compared to 2002.
Potential Uses of Liquidity
Planned Capital Expenditures & Investments
Capital expenditures and investments in nonregulated unconsolidated affiliates
for the remainder of 2003 are estimated to be approximately $205 million.
Ratings Triggers
At March 31, 2003, $113.0 million of Cap Corp's senior unsecured notes were
subject to cross-default and ratings trigger provisions that would provide that
the full balance outstanding is subject to prepayment if the ratings of Indiana
Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a make
whole amount based on the discounted value of the remaining payments due on the
notes would also become payable. Indiana Gas' and SIGECO's ratings remain at one
level above the ratings trigger. Effective January 1, 2003, the Company
transferred assets which primarily supported the Utility Group's operations to
VUHI in order to make available approximately $90 million of additional
nonregulated and corporate capacity.
Other Guarantees and Letters of Credit
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees may include posted letters of credit, debt and leasing guarantees,
performance guarantees, and energy saving guarantees and may periodically
include the debt of and performance obligations of unconsolidated affiliates.
The Company estimates these guarantees totaled approximately $115 million at
March 31, 2003, including outstanding letters of credit. The Company's most
significant guarantee approximating $60 million represents two-thirds of Energy
Systems Group, LLC's (ESG) surety bonds, performance guarantees, and energy
savings guarantees. The guarantees relate to amounts due to various insurance
companies for surety bonds should ESG default on obligations to complete
construction, pay vendors or subcontractors, or to achieve energy guarantees.
Through March 31, 2003, the Company has not been called upon to satisfy any
obligations pursuant to its guarantees. ESG was a two-thirds owned consolidated
subsidiary at March 31, 2003. Subsequent to March 31, 2003, the Company
purchased the remaining interest in ESG for approximately $4 million.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unusual maintenance or repairs;
unanticipated changes to fossil fuel costs; unanticipated changes to gas
supply costs, or availability due to higher demand, shortages,
transportation problems or other developments; environmental or pipeline
incidents; transmission or distribution incidents; unanticipated changes to
electric energy supply costs, or availability due to demand, shortages,
transmission problems or other developments; or electric transmission or
gas pipeline system constraints.
o Increased competition in the energy environment including effects of
industry restructuring and unbundling.
o Regulatory factors such as unanticipated changes in rate-setting policies
or procedures, recovery of investments and costs made under traditional
regulation, and the frequency and timing of rate increases.
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board; the Securities and Exchange
Commission; the Federal Energy Regulatory Commission; state public utility
commissions; state entities which regulate electric and natural gas
transmission and distribution, natural gas gathering and processing,
electric power supply; and similar entities with regulatory oversight.
o Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
o Changing market conditions and a variety of other factors associated with
physical energy and financial trading activities including, but not limited
to, price, basis, credit, liquidity, volatility, capacity, interest rate,
and warranty risks.
o The performance of projects undertaken by the Company's nonregulated
businesses and the success of efforts to invest in and develop new
opportunities, including but not limited to, the realization of Section 29
income tax credits and the Company's coal mining, gas marketing, and
broadband strategies.
o Direct or indirect effects on our business, financial condition or
liquidity resulting from a change in our credit rating, changes in interest
rates, and/or changes in market perceptions of the utility industry and
other energy-related industries.
o Employee workforce factors including changes in key executives, collective
bargaining agreements with union employees, or work stoppages.
o Legal and regulatory delays and other obstacles associated with mergers,
acquisitions, and investments in joint ventures.
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but not
limited to, those described in Management's Discussion and Analysis of
Results of Operations and Financial Condition.
o Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to various business risks associated with commodity
prices, interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program. The Company's risk management program includes, among other
things, the use of derivatives to mitigate risk.
The Company also executes derivative contracts in the normal course of
operations while buying and selling commodities and other fungible goods to be
used in operations and while optimizing generation assets. The Company does not
execute derivative contracts for speculative or trading purposes.
These risks are not significantly different from the information set forth in
Item 7A Quantitative and Qualitative Disclosures About Market Risk included in
the Vectren 2002 Form 10-K and is therefore not presented herein.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Within 90 days prior to the filing of the report, the Company carried out an
evaluation under the supervision and with the participation of the Chief
Executive Officer and Chief Financial Officer of the effectiveness and the
design and operation of the Company's disclosure controls and procedures. Based
on that evaluation, the Chief Executive Officer and the Chief Financial Officer
have concluded that the Company's disclosure controls and procedures are
effective in bringing to their attention on a timely basis material information
relating to the Company required to be disclosed by the Company in its filings
under the Securities Exchange Act of 1934 (Exchange Act).
Disclosure controls and procedures, as defined by the Exchange Act in Rules
13a-14(c) and 15d-14(c), are controls and other procedures of the Company that
are designed to ensure that information required to be disclosed by the Company
in the reports filed or submitted by it under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the
SEC's rules and forms. "Disclosure controls and procedures" include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Company in its Exchange Act reports is accumulated and
communicated to the Company's management, including its principal executive and
financial officers, as appropriate to allow timely decisions regarding required
disclosure.
The Company has investments in unconsolidated affiliates. As the Company does
not control or manage these affiliates, its disclosure controls and procedures
with respect to them are more limited than the disclosure controls and
procedures maintained within the Company's consolidated subsidiaries.
Changes in Internal Control
Since the evaluation of disclosure controls and procedures, there have been no
significant changes to the Company's internal controls and procedures or
significant changes in other factors that could significantly affect the
Company's internal controls and procedures.
Internal control, as defined in American Institute of Certified Public
Accountants Codification of Statements on Auditing Standards (AU ss.319), is a
process, effected by an entity's board of directors, management, and other
personnel, designed to provide reasonable assurance regarding the achievement of
objectives in the following categories: (a) reliability of financial reporting,
(b) effectiveness and efficiency of operations and (c) compliance with
applicable laws and regulations.
PART II. OTHER INFORMATION
ITEM 1. 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 9 of its unaudited
consolidated condensed financial statements included in Part 1 Item 1 Financial
Statements regarding the Clean Air Act and related legal proceedings.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports On Form 8-K During The Last Calendar Quarter
On January 31, 2003, Vectren Corporation filed a Current Report on Form 8-K with
respect to the release of preliminary financial information to the investment
community regarding the Company's results of operations, for the three and
twelve month periods ended December 31, 2002. The financial information was
released to the public through this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Vectren Reports Preliminary 2002 Results
99.2 - 2002 Selected Financial Data and Effects of Restatement
99.3 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
On March 14, 2003, Vectren Corporation filed a Current Report on Form 8-K with
respect to the release of financial information to the investment community
regarding the Company's results of operations, financial position and cash flows
for the three and twelve month periods ended December 31, 2002. The financial
information was released to the public through this filing.
Item 9. Regulation FD Disclosure
Item 7. Exhibits
99.1 - Press Release - Vectren Reports Final 2002 Earnings
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
On March 31, 2003, Vectren Corporation filed a Current Report on Form 8-K with
respect to amending disclosure its annual report on Form 10-K such disclosure
would be compliant with Regulation G.
Item 5. Other Events.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
VECTREN CORPORATION
-------------------
Registrant
May 15, 2003 /s/Jerome A. Benkert, Jr.
-------------------------
Jerome A. Benkert, Jr.
Executive Vice President &
Chief Financial Officer
(Principal Financial Officer)
/s/M. Susan Hardwick
-------------------------
M. Susan Hardwick
Vice President & Controller
(Principal Accounting Officer)
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CHIEF EXECUTIVE OFFICER CERTIFICATION
I, Niel C. Ellerbrook, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Vectren Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 15, 2003
/s/ Niel C. Ellerbrook
---------------------------------------------
Niel C. Ellerbrook
Chairman, President, & Chief Executive Officer
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CHIEF FINANCIAL OFFICER CERTIFICATION
I, Jerome A. Benkert, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Vectren Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 15, 2003
/s/ Jerome A. Benkert, Jr.
----------------------------------------------
Jerome A. Benkert, Jr.
Executive Vice President &
Chief Financial Officer
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
By signing below, each of the undersigned officers hereby certifies pursuant to
18 U.S.C. ss. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, that, to his or her knowledge, (i) this report fully complies with the
requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
and (ii) the information contained in this report fairly presents, in all
material respects, the financial condition and results of operations of Vectren
Corporation.
Signed this 15th day of May, 2003.
/s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook
- ---------------------------------- ---------------------------------------
(Signature of Authorized Officer) (Signature of Authorized Officer)
Jerome A. Benkert, Jr. Niel C. Ellerbrook
- ---------------------------------- ---------------------------------------
(Typed Name) (Typed Name)
Executive Vice President & Chairman, President,
Chief Financial Officer & Chief Executive Officer
- ---------------------------------- ---------------------------------------
(Title) (Title)