UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For quarterly period ended September 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from to
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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 (I.R.S. Employer
incorporation or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices and 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 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 67,788,325 November 1, 2002
- -------------------------------- --------------------- -------------------
Class Number of shares Date
Table of Contents
Item Page
Number Number
Part I. Financial Information
Financial Statements (Unaudited)
Consolidated Condensed Balance Sheets........................... 1-2
Consolidated Condensed Statements of Income..................... 3
Consolidated Condensed Statements of Cash Flows............. ... 4
Notes to Consolidated Condensed Unaudited Financial Statements.. 5-14
Management's Discussion and Analysis
of Results of Operations and Financial Condition................. 15-32
Qualitative and Quantitative Disclosures About Market Risk........ 33-34
Controls and Procedures........................................... 35
Part II. Other Information
Legal Proceedings................................................. 36
Exhibits and Reports on Form 8-K.................................. 36
Signatures........................................................ 37
Certifications.................................................... 38-40
Definitions
As discussed in this Form 10-Q, the abbreviations
AFUDC means allowance for funds used during construction
APB means Accounting Principles Board
EITF means Emerging Issues Task Force
FASB means Financial Accounting Standards Board
IDEM means Indiana Department of Environmental Management
IURC means Indiana Utility Regulatory Commission
MMDth means millions of dekatherms
MMBTU means millions of British thermal units
PUCO means Public Utilities Commission of Ohio
SFAS means Statement of Financial Accounting Standards
USEPA means United States Environmental Protection Agency
Throughput means combined gas sales and gas transportation volumes
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
September 30, December 31,
2002 2001
------------ ------------
ASSETS
Current Assets
Cash & cash equivalents $ 18.6 $ 27.2
Accounts receivable-less reserves of $7.0 &
$5.9, respectively 99.8 213.8
Accrued unbilled revenues 31.3 78.4
Inventories 58.4 71.4
Recoverable fuel & natural gas costs 45.3 76.5
Prepayments & other current assets 107.4 103.4
-------- --------
Total current assets 360.8 570.7
-------- --------
Utility Plant
Original cost 2,987.0 2,903.2
Less: accumulated depreciation & amortization 1,367.3 1,308.2
-------- --------
Net utility plant 1,619.7 1,595.0
-------- --------
Investments in unconsolidated affiliates 150.0 127.7
Other investments 118.4 100.3
Non-utility property-net 210.2 181.7
Goodwill-net 199.3 199.3
Regulatory assets 80.0 61.4
Other assets 29.6 20.7
-------- --------
TOTAL ASSETS $ 2,768.0 $ 2,856.8
======== ========
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)
September 30, December 31,
2002 2001
------------ -----------
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 97.8 $ 144.4
Accounts payable to affiliated companies 32.8 37.2
Accrued liabilities 99.8 101.4
Short-term borrowings 314.0 381.7
Long-term debt subject to tender - 11.5
Current maturities of long-term debt 17.3 1.3
-------- --------
Total current liabilities 561.7 677.5
-------- --------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 221.6 206.7
Deferred credits & other liabilities 114.5 108.1
-------- --------
Total deferred income taxes &
other liabilities 336.1 314.8
-------- --------
Commitments & Contingencies (Notes 6 - 8)
Minority Interest in Subsidiary 1.5 1.4
Capitalization
Long-term debt-net of current maturities and
debt subject to tender 1,003.3 1,014.0
Cumulative redeemable preferred
stock of subsidiary 0.3 0.5
Common shareholders' equity
Common stock (no par value) - issued &
outstanding 67.8 and 67.7, respectively 348.3 346.1
Retained earnings 518.0 498.3
Accumulated other comprehensive income (1.2) 4.2
-------- --------
Total common shareholders' equity 865.1 848.6
-------- --------
Total capitalization 1,868.7 1,863.1
-------- --------
TOTAL LIABILITIES &
SHAREHOLDERS' EQUITY $ 2,768.0 $ 2,856.8
======== ========
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 Nine Months
Ended Ended
September 30, September 30,
---------------- -------------------
2002 2001 2002 2001
------ ------- -------- --------
OPERATING REVENUES
Gas utility $ 88.1 $ 96.0 $ 585.0 $ 774.3
Electric utility 190.0 104.3 475.7 287.5
Energy services & other 26.4 156.4 265.9 611.9
------ ------- -------- --------
Total operating revenues 304.5 356.7 1,326.6 1,673.7
------ ------- -------- --------
OPERATING EXPENSES
Cost of gas sold 45.7 51.2 357.6 550.1
Fuel for electric generation 22.9 21.1 59.7 56.9
Purchased electric energy 92.5 22.6 239.3 69.4
Cost of energy services & other 16.4 143.7 234.9 582.5
Other operating 54.3 55.2 168.3 175.7
Merger & integration costs - 1.3 - 2.1
Restructuring costs - 2.6 - 14.4
Depreciation & amortization 30.4 32.3 88.2 95.6
Taxes other than income taxes 9.8 9.3 38.3 39.9
------ ------- -------- --------
Total operating expenses 272.0 339.3 1,186.3 1,586.6
------ ------- -------- --------
OPERATING INCOME 32.5 17.4 140.3 87.1
OTHER INCOME
Equity in earnings of
unconsolidated affiliates 1.7 4.9 7.8 15.0
Other - net 3.5 3.6 12.6 11.5
------ ------- -------- --------
Total other income 5.2 8.5 20.4 26.5
------ ------- -------- --------
Interest expense 19.5 18.8 58.6 62.6
------ ------- -------- --------
INCOME BEFORE INCOME TAXES 18.2 7.1 102.1 51.0
------ ------- -------- --------
Income taxes 3.9 1.4 28.1 14.5
Minority interest in subsidiary 0.3 1.0 0.1 0.8
Preferred dividend requirement
of subsidiary - 0.2 - 0.7
------ ------- -------- --------
INCOME BEFORE EXTRAORDINARY
LOSS & CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 14.0 4.5 73.9 35.0
------ ------- -------- --------
Extraordinary loss - net of tax - - - (7.7)
Cumulative effect of change in
accounting principle - net of tax - - - 3.9
------ ------- -------- --------
NET INCOME $ 14.0 $ 4.5 $ 73.9 $ 31.2
====== ======= ======== ========
AVERAGE COMMON SHARES OUTSTANDING 67.6 67.5 67.6 66.5
DILUTED COMMON SHARES OUTSTANDING 67.8 67.7 67.8 66.6
EARNINGS PER SHARE OF COMMON STOCK:
BASIC
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE $ 0.21 $ 0.07 $ 1.09 $ 0.53
Extraordinary loss - net of tax - - - (0.12)
Cumulative effect of change in
accounting principle - net of tax - - - 0.06
------ ------- -------- --------
BASIC EARNINGS PER SHARE OF
COMMON STOCK $ 0.21 $ 0.07 $ 1.09 $ 0.47
====== ======= ======== ========
DILUTED
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE $ 0.21 $ 0.07 $ 1.09 $ 0.53
Extraordinary loss - net of tax - - - (0.12)
Cumulative effect of change in
accounting principle - net of tax - - - 0.06
------ ------- -------- --------
DILUTED EARNINGS PER SHARE OF
COMMON STOCK $ 0.21 $ 0.07 $ 1.09 $ 0.47
====== ======= ======== ========
DIVIDENDS DECLARED PER SHARE OF
COMMON STOCK $ 0.27 $ 0.26 $ 0.80 $ 0.77
====== ======= ======== ========
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)
Nine Months
Ended September 30,
------------------
2002 2001
------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 73.9 $ 31.2
Adjustments to reconcile net income to
cash from operating activities:
Depreciation & amortization 88.2 95.6
Deferred income taxes & investment tax credits 5.9 (7.8)
Equity in earnings of unconsolidated affiliates (7.8) (15.0)
Extraordinary loss- net of tax - 7.7
Net unrealized loss (gain) on derivative instruments,
including cumulative effect of change in accounting
principle 3.0 (3.0)
Other non-cash charges-net 7.9 6.2
Changes in assets and liabilities:
Accounts receivable & accrued unbilled revenues 108.7 247.4
Inventories 5.3 (8.0)
Recoverable fuel & natural gas costs 31.2 17.1
Prepayments & other current assets (5.3) (31.1)
Regulatory assets - (0.6)
Accounts payable, including to affiliated companies (15.1) (180.7)
Accrued liabilities (9.6) (15.1)
Other noncurrent assets & liabilities (13.1) 7.4
------ ------
Total adjustments 199.3 120.1
------ ------
Net cash flows from operating activities 273.2 151.3
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CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES
Proceeds from:
Issuance of common stock - net of issuance costs - 129.4
Requirements for:
Dividends on common stock (53.7) (51.6)
Retirement of long-term debt (6.4) (7.5)
Redemption of preferred stock of subsidiary (0.2) (17.7)
Dividends on preferred stock of subsidiary - (0.7)
Net change in short-term borrowings (63.6) (104.1)
Proceeds from exercise of stock options & other 1.1 (0.2)
------ ------
Net cash flows (required for) financing activities (122.8) (52.4)
------ ------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from:
Sale of leveraged lease investments - 46.7
Unconsolidated affiliate distributions 5.3 10.7
Other investments 3.9 -
Requirements for:
Capital expenditures (150.2) (142.0)
Unconsolidated affiliates (9.0) (24.1)
Other investments (9.0) (1.9)
------ ------
Net cash flows (required for) investing activities (159.0) (110.6)
------ ------
Net (decrease) increase in cash & cash equivalents (8.6) (11.7)
Cash & cash equivalents at beginning of period 27.2 15.2
------ ------
Cash & cash equivalents at end of period $ 18.6 $ 3.5
====== ======
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 Accounting Principles
Board (APB) Opinion No.
16 "Business Combinations."
Vectren is a public utility holding company, whose wholly owned subsidiary,
Vectren Utility Holdings, Inc. (VUHI), is the intermediate holding company for
the Company's 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. Indiana Gas provides natural gas distribution
and transportation services to a diversified customer base in 311 communities in
49 of Indiana's 92 counties. SIGECO provides electric generation, transmission,
and distribution services to Evansville, Indiana, and 74 other communities in 8
counties in southwestern Indiana and participates in the wholesale power market.
SIGECO also provides natural gas distribution and transportation services to
Evansville, Indiana, and 64 communities in 10 counties in southwestern Indiana.
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
Dayton, Ohio, and 87 other communities in 17 counties in west central Ohio. The
Ohio operations were acquired from The Dayton Power & Light Company on October
31, 2000. 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.
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, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates Internal Revenue Service (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 investments in other businesses that
invest in energy-related opportunities and provide utility services, municipal
broadband consulting, retail services, and real estate and leveraged lease
investments.
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, 2001, 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.
Certain reclassifications have been made to prior period financial statements to
conform with the current year classification. These reclassifications have no
impact on previously reported net income.
3. Impact of Recently Issued Accounting Guidance
EITF 02-03
- ----------
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133) should be shown net in the income
statement, whether or not settled physically, if the derivative instruments are
eld for "trading purposes." The consensus rescinded EITF 98-10 "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities"
(EITF 98-10) as well as other decisions reached on energy trading contracts at
the EITF's June 2002 meeting.
The Company's power marketing operations enter into contracts that are
derivatives as defined by SFAS 133, but these operations do not met the
definition of energy trading activities based upon the provisions in EITF 98-10.
Currently, the Company uses a gross presentation to report the results of these
operations. The Company will re-evaluate its portfolio of derivative contracts
to determine if any will be required to be reported net in accordance with the
provisions of the new consensus.
The consensus relating to the presentation of gains and losses on derivative
instruments held for "trading purposes" is effective for financial statements
issued for periods beginning after December 15, 2002 and requires the
reclassification of all periods presented. For the Company, the consensus is
effective beginning January 1, 2003. See Note 9 for additional information on
the Company's power marketing operations.
SFAS 142
- --------
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS 142). The Company adopted the provisions of SFAS 142, as required
on January 1, 2002. SFAS 142 changed the accounting for goodwill from an
amortization approach to an impairment-only approach. Thus, amortization of
goodwill that is not included as an allowable cost for rate-making purposes
ceased upon adoption of this statement. This includes goodwill recorded in past
business combinations, such as the Company's acquisition of the Ohio operations.
Goodwill is to be tested for impairment at a reporting unit level at least
annually.
SFAS 142 also required the initial impairment review of all goodwill within six
months of the adoption date. The impairment review consisted of a comparison of
the fair value of a reporting unit to its carrying amount. If the fair value of
a reporting unit is less than its carrying amount, an impairment loss would be
recognized. Results of the initial impairment review were to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations. SFAS 142 also changed certain aspects of accounting for other
intangible assets; however, the Company does not have any other significant
intangible assets.
As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations, which approximates $5.0 million per year and is included in
the Gas Utility Services operating segment, ceased on January 1, 2002. Initial
impairment reviews to be performed within six months of adoption of SFAS 142
were completed and resulted in no impairment.
SFAS 144
- --------
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations are no longer
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
The adoption of SFAS 144 on January 1, 2002 did not materially impact
operations.
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. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
4. Comprehensive Income
Comprehensive income consists of the following:
Three Months Nine Months
Ended September 30, Ended September 30,
------------------ ------------------
In millions 2002 2001 2002 2001
- ----------- ------- ------ ------- -------
Net income (loss) $ 14.0 $ 4.5 $ 73.9 $ 31.2
Comprehensive income (loss) of
unconsolidated affiliates-net of tax (5.0) (2.1) (5.2) (13.2)
Minimum pension liability adjustment
and other-net of tax (0.1) (3.0) (0.1) (4.0)
------- ------ ------- -------
Total comprehensive income (loss) $ 8.9 $ (0.6) $ 68.6 $ 14.0
======= ====== ======= =======
Comprehensive income arising from unconsolidated affiliates is the Company's
portion of ProLiance Energy LLC's and Reliant Services, LLC's other
comprehensive income related to its use of cash flow hedges, including commodity
contracts and interest rate swaps, and the Company's portion of Haddington
Energy Partners, LP other comprehensive income related to unrealized gains and
losses of available-for-sale securities.
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 and nine months ended September 30, 2002 and 2001:
In millions, except Three Months Ended September 30,
--------------------------------
per share amounts 2002 2001
- ----------------- --------------------------- -------------------------
Per Per
Share Share
Income Shares Amount Loss Shares Amount
--------------------------- -------------------------
Basic EPS $ 14.0 67.6 $ 0.21 $ 4.5 67.5 $ 0.07
Effect of dilutive
stock equivalents 0.2 0.2
------ ---- ----- ---- ---- -----
Diluted EPS $ 14.0 67.8 $ 0.21 $ 4.5 67.7 $ 0.07
====== ==== ===== ==== ==== =====
Nine Months Ended September 30,
--------------------------------
2002 2001
--------------------------- --------------------------
Per Per
Share Share
Income Shares Amount Income Shares Amount
--------------------------- ------- ----------------
Basic EPS $ 73.9 67.6 $ 1.09 $31.2 66.5 $ 0.47
Effect of dilutive
stock equivalents 0.2 0.1
------ ---- ----- ----- ---- -----
Diluted EPS $ 73.9 67.8 $ 1.09 $31.2 66.6 $ 0.47
====== ==== ===== ===== ==== =====
For the three months ended September 30, 2002 and 2001, options to purchase
87,963 and 870,821 common shares of the Company's common stock were outstanding,
but were not included in the computation of diluted earnings per share because
their effect would be antidilutive. Exercise prices for options excluded from
the computation ranged from $24.05 to $25.59 in 2002 and ranged from $22.54 to
$24.05 in 2001.
For the nine months ended September 30, 2002 and 2001, options to purchase
22,274 and 870,821 common shares of the Company's common stock were outstanding,
but were not included in the computation of diluted earnings per share because
their effect would be antidilutive. Exercise prices for options excluded from
the computation ranged from $24.90 to $25.59 in 2002 and ranged from $22.54 to
$24.05 in 2001.
6. Commitments & Contingencies
Guarantees
- ----------
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees include debt guarantees and performance guarantees, including the
debt of and performance of energy efficiency products installed by affiliated
companies. The Company estimates these guarantees totaled approximately $90
million at September 30, 2002. The Company's most significant guarantee totaling
$59.8 million represents two-thirds of Energy Systems Group, LLC's (ESG) surety
bonds, performance and energy savings guarantees. ESG is a two-thirds owned
consolidated subsidiary. 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 September 30, 2002, the Company has not been called upon to
satisfy any obligations pursuant to the guarantees.
Legal Proceedings
- -----------------
The Company is party to various legal and regulatory 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 7
regarding ProLiance Energy, LLC and Note 8 regarding environmental matters.
7. Unconsolidated Affiliates
ProLiance Energy, LLC
- ---------------------
ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), began providing
natural gas and related services to Indiana Gas, Citizens Gas, and others in
April 1996. ProLiance also provides services to the Ohio operations and began
providing service to SIGECO in 2002. ProLiance's primary business is optimizing
the gas portfolios of utilities and providing services to large end use
customers.
Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC
In February 2002, Vectren announced its intention to integrate the operations of
its wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance.
SES provides natural gas and related services to SIGECO and others. Effective
June 1, 2002, the integration was completed. In exchange for the contribution of
SES' net assets totaling $19.2 million, including cash of $2.0 million,
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. 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. Additionally, the non-cash component of the transfer
totaling $17.2 million is excluded from the Consolidated Condensed Statement of
Cash Flows.
Regulatory Matters
The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) process administered by the
PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility. The
IURC's decision reflected the significant gas cost savings to customers obtained
through ProLiance's services and suggested that all material provisions of the
agreements between ProLiance and the utilities were reasonable. Nevertheless,
with respect to the pricing of gas commodity purchased from ProLiance, the price
paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in the pending, consolidated GCA proceeding involving Indiana
Gas and Citizens Gas.
In 2001, the IURC commenced processing the GCA proceeding regarding the three
pricing issues. The IURC indicated that it would consider the prospective
relationship of ProLiance with the utilities in this proceeding. On June 4,
2002, Indiana Gas and Citizens Gas, together with the Office of Utility Consumer
Counselor and other consumer parties, entered into and filed with the IURC a
settlement setting forth the terms for resolution of all pending regulatory
issues related to ProLiance. On July 23, 2002, the IURC approved the settlement
filed by the parties. The GCA proceeding has been concluded and new supply
agreements between Indiana Gas, SIGECO, Citizens Gas, and ProLiance have been
approved and extended through March 31, 2007. At September 30, 2002 and December
31, 2001, the Company has reserved approximately $4.4 million and $3.2 million,
respectively, of ProLiance's after tax earnings for exposure from this GCA
proceeding which approximates the impact of the settlement for past services
provided to Indiana Gas by ProLiance. The Company expects refunds to retail
customers to be applied to the reserve in December 2002.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
three months ended September 30, 2002 and 2001 totaled $96.6 million and $89.3
million, respectively; and for the nine months ended September 30, 2002 and 2001
totaled $332.9 million and $503.7 million, respectively. Amounts owed to
ProLiance at September 30, 2002 and December 31, 2001 for those purchases were
$31.4 million and $36.1 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.
Utilicom Networks, LLC
- ----------------------
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including analog and digital
cable television, high-speed Internet, and advanced local and long distance
phone services. The Company has a minority equity interest and convertible
subordinated debt investment in Utilicom. The Company also has a minority
interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to
hold interests in SIGECOM, LLC (SIGECOM). The Company accounts for its
investments in Utilicom and Holdings on the cost method. SIGECOM provides
broadband services to the greater Evansville, Indiana, area. Utilicom also plans
to provide broadband services to the greater Indianapolis, Indiana, and Dayton,
Ohio, markets.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is 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 are still committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded.
Franchising agreements have been extended in both locations.
8. 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 United States Environmental
Protection Agency (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 1998 and 1999.
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.
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. 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 September 30, 2002,
$53.5 million has been expended. 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 October 22, 2002,
the Company filed a settlement agreement with the IURC that has been entered
into with the Indiana Office of Utility Consumer Counselor and an industrial
intervenor group relating to the ongoing NOx project. The agreement, if approved
by the IURC, will authorize additional capital cost investment 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. A hearing is scheduled for November 15, 2002 to consider the
agreement. The settlement establishes a fixed return of 8 percent on the capital
investment.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
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. 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
compliant. 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 March 31, 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 expert 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 June of 2002, the Company received a request from the IDEM concerning
information on any manufactured gas plant sites which the Company has not
enrolled in IDEM's Voluntary Remediation Program, specifically five sites which
were owned and/or operated by SIGECO. Preliminary site investigations conducted
by SIGECO in the mid-1990's confirmed that based upon the conditions known at
the time, the sites posed no risk to human health or the environment.
9. Energy Marketing Activities
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to optimize the return
on these key assets. The contracts entered into are primarily short-term
purchase and sale contracts that expose the Company to limited market risk.
During 2002, the Company has increased its activity in the wholesale market.
With the exception of those contracts subject to the normal purchase and sale
exclusion, commodity contracts are accounted for at market value. As of
September 30, 2002, contracts had a no net asset value compared to a net asset
value of $3.2 million at December 31, 2001. The Company has determined these
power marketing contracts are derivatives within the scope of SFAS No. 133.
Contracts recorded at market value are recorded as current or noncurrent assets
or liabilities in the Consolidated Condensed Balance Sheets depending on their
value and on when the contracts are expected to be settled. Changes in market
value, which is a function of the normal decline in fair value as earnings are
realized and the fluctuation in fair value resulting from price volatility, are
recorded in purchased electric energy in the Consolidated Condensed Statements
of Income. Market value is determined using quoted market prices from
independent sources.
Forward sale contracts, premiums received for written options, and proceeds
received from exercised options are recorded when settled as electric utility
revenues in the Consolidated Condensed Statements of Income. Forward purchase
contracts, premiums paid for purchased options, and proceeds paid for exercising
options are recorded when settled in purchased electric energy in the
Consolidated Condensed Statements of Income. Contracts with counter-parties
subject to master netting arrangements are presented net in the Consolidated
Condensed Balance Sheets.
Power marketing contracts at September 30, 2002 totaled $7.7 million of
prepayments and other current assets and $7.7 million of accrued liabilities,
compared to $5.2 million of prepayments and other current assets and $2.0
million of accrued liabilities at December 31, 2001. For the three months ended
September 30, 2002 and 2001, the change in the net value of these contracts
includes an unrealized gain of $0.2 million and an unrealized loss of $0.9
million, respectively. For the nine months ended September 30, 2002 and 2001,
the change in the net value of these contracts includes unrealized losses of
$3.0 million and $3.3 million, respectively. Including these unrealized changes
in fair value, overall margin (revenue net of purchased power) from power
marketing operations for the three months ended September 30, 2002 and 2001 was
$4.6 million and $4.1 million, respectively, and for the nine months ended
September 30, 2002 and 2001 was $8.0 million and $10.9 million, respectively.
10. Segment Reporting
The Company had four operating segments during the three and nine months ended
September 30, 2002: (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 to primarily southwestern
Indiana, and SIGECO's power generating and power marketing operations. 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 provides general
and administrative support and assets, including computer hardware and software,
to the Company's other operating segments. Data for the three and nine months
ended September 30, 2001 has been restated to conform to the current year
presentation. The following tables provide information about business segments.
Three Months Nine Months
Ended September 30, Ended September 30,
------------------ ---------------------
In millions 2002 2001 2002 2001
------- ------- --------- ---------
Operating Revenues
Gas Utility Services $ 88.1 $ 96.0 $ 585.0 $ 774.3
Electric Utility Services 190.0 104.3 475.7 287.5
Nonregulated Operations 44.2 164.2 313.6 641.2
Corporate & Other 4.9 7.4 16.2 25.3
Intersegment Eliminations (22.7) (15.2) (63.9) (54.6)
------ ------- -------- --------
Total operating revenues $ 304.5 $ 356.7 $ 1,326.6 $ 1,673.7
====== ======= ======== ========
Net Income (Loss)
Gas Utility Services $ (14.4) $ (13.0) $ 15.4 $ (10.3)
Electric Utility Services 23.3 12.5 43.2 32.6
Nonregulated Operations 5.8 6.0 14.8 10.9
Corporate & Other (0.7) (1.0) 0.5 (2.0)
------ ------- -------- --------
Net income (loss) $ 14.0 $ 4.5 $ 73.9 $ 31.2
====== ======= ======== ========
September 30, December 31,
2002 2001
-------- --------
Identifiable Assets
Gas Utility Services $1,459.3 $1,580.2
Electric Utility Services 842.6 811.2
Nonregulated Operations 394.0 466.1
Corporate & Other 160.2 152.4
Intersegment Eliminations (88.1) (153.1)
-------- --------
Total identifiable assets $2,768.0 $2,856.8
======== ========
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."
Vectren is a public utility holding company, whose wholly owned subsidiary,
Vectren Utility Holdings, Inc. (VUHI), is the intermediate holding company for
the Company's 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. Indiana Gas provides natural gas distribution
and transportation services to a diversified customer base in 311 communities in
49 of Indiana's 92 counties. SIGECO provides electric generation, transmission,
and distribution services to Evansville, Indiana, and 74 other communities in 8
counties in southwestern Indiana and participates in the wholesale power market.
SIGECO also provides natural gas distribution and transportation services to
Evansville, Indiana, and 64 communities in 10 counties in southwestern Indiana.
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
Dayton, Ohio, and 87 other communities in 17 counties in west central Ohio. The
Ohio operations were acquired from The Dayton Power & Light Company on October
31, 2000. 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.
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, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates Internal Revenue Service (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 investments in other businesses that
invest in energy-related opportunities and provide utility services, municipal
broadband consulting, retail services, and real estate and leveraged lease
investments.
Consolidated Results of Operations
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
In millions, except per share amounts 2002 2001 2002 2001
- ------------------------------------- -------- ------ ------- -------
Net income, as reported $ 14.0 $ 4.5 $ 73.9 $ 31.2
Restructuring costs - net of tax - 1.6 - 8.9
Merger, integration, & other costs - net of tax - 2.5 - 6.5
Extraordinary loss - net of tax - - - 7.7
Cumulative effect of change in accounting
principle - net of tax - - - (3.9)
------ ----- ------ ------
Net income before nonrecurring items $ 14.0 $ 8.6 $ 73.9 $ 50.4
====== ===== ====== ======
Attributed to:
Regulated $ 8.9 $ 2.7 $ 58.6 $ 32.3
Nonregulated 5.8 6.9 14.8 19.9
Corporate & other (0.7) (1.0) 0.5 (1.8)
------ ----- ------ ------
Basic earnings per share, as reported $ 0.21 $ 0.07 $ 1.09 $ 0.47
Restructuring costs - 0.02 - 0.13
Merger, integration, & other costs - 0.04 - 0.10
Extraordinary loss - - - 0.12
Cumulative effect of change in
accounting principle - - - (0.06)
------ ----- ------ ------
Basic earnings per share before
nonrecurring items $ 0.21 $ 0.13 $ 1.09 $ 0.76
====== ===== ====== ======
Attributed to:
Regulated $ 0.13 $ 0.04 $ 0.87 $ 0.49
Nonregulated 0.09 0.10 0.22 0.30
Corporate & other (0.01) (0.01) - (0.03)
Overview
- --------
For the three months ended September 30, 2002, net income was $14.0 million, or
$0.21 per share, compared to net income of $4.5 million, or $0.07 per share in
2001. For the nine months ended September 30, 2002, net income was $73.9
million, or $1.09 per share, compared to net income of $31.2 million, or $0.47
per share in 2001. The $9.5 million increase for the three-month period and the
$42.7 million increase for the nine-month period results partly from the
nonrecurring charges related to merger and integration and restructuring
reported in 2001. The increase for the nine-month period also includes an
extraordinary loss resulting from leveraged lease dispositions reported in 2001,
offset by the cumulative effect recorded on adoption of SFAS No. 133 "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133).
Net income before the impact of these nonrecurring items for the nine months
ended September 30, 2002 increased $23.5 million. The increase was primarily
attributable to improved margins and lower operations and maintenance costs.
These resulted from a return to lower gas prices and the related reduction in
costs incurred in 2001, favorable cooling weather during the second and third
quarters, and merger synergies. The accrual of carrying costs on the Company's
demand side management programs consistent with an existing IURC rate order and
increased nonregulated earnings from the Energy Marketing and Services Group and
Coal Mining Group also contributed.
For the three months ended September 30, 2002, net income before the impact of
nonrecurring items increased $5.4 million when compared to 2001. The increase is
primarily attributable to increased margins of the regulated operations, partly
reflecting favorable cooling weather.
Dividends
- ---------
Dividends declared for the three and nine months ended September 30, 2002 were
$0.265 per share and $0.795 per share, respectively, compared to $0.255 per
share and $0.765 per share for the same periods in 2001.
New Accounting Principles
- -------------------------
EITF 02-03
- ----------
In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that gains and losses (realized and unrealized) on all derivative
instruments within the scope of SFAS 133 should be shown net in the income
statement, whether or not settled physically, if the derivative instruments are
held for "trading purposes." The consensus rescinded EITF 98-10 "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities"
(EITF 98-10) as well as other decisions reached on energy trading contracts at
the EITF's June 2002 meeting.
The Company's power marketing operations enter into contracts that are
derivatives as defined by SFAS 133, but these operations do not met the
definition of energy trading activities based upon the provisions in EITF 98-10.
Currently, the Company uses a gross presentation to report the results of these
operations. The Company will re-evaluate its portfolio of derivative contracts
to determine if any will be required to be reported net in accordance with the
provisions of the new consensus.
The consensus relating to the presentation of gains and losses on derivative
instruments held for "trading purposes" is effective for financial statements
issued for periods beginning after December 15, 2002 and requires the
reclassification of all periods presented. For the Company, the consensus is
effective beginning January 1, 2003.
SFAS 142
- --------
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted the
provisions of SFAS 142, as required on January 1, 2002. SFAS 142 changed the
accounting for goodwill from an amortization approach to an impairment-only
approach. Thus, amortization of goodwill that is not included as an allowable
cost for rate-making purposes ceased upon adoption of this statement. This
includes goodwill recorded in past business combinations, such as the Company's
acquisition of the Ohio operations. Goodwill is to be tested for impairment at a
reporting unit level at least annually.
SFAS 142 also required the initial impairment review of all goodwill within six
months of the adoption date. The impairment review consisted of a comparison of
the fair value of a reporting unit to its carrying amount. If the fair value of
a reporting unit is less than its carrying amount, an impairment loss would be
recognized. Results of the initial impairment review were to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations. SFAS 142 also changed certain aspects of accounting for other
intangible assets; however, the Company does not have any significant other
intangible assets.
As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations, which approximates $5.0 million per year and is included in
the Gas Utility Services operating segment, ceased on January 1, 2002. Initial
impairment reviews to be performed within six months of adoption of SFAS 142
were completed and resulted in no impairment.
SFAS 144
- --------
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations are no longer
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
The adoption of SFAS 144 on January 1, 2002 did not materially impact
operations.
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 the
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. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
Indiana Tax Legislation
- -----------------------
The Indiana General Assembly enacted tax-restructuring legislation in June 2002
that included an increase in taxes imposed on income, effectively increasing
Vectren's state income tax rate from 4.5% to 8.5%. Other changes in Indiana tax
provisions include reductions in property taxes and the repeal of the Gross
Income Tax coupled with the enactment of a new Utility Receipts Tax. Although
the new law is not effective until January 1, 2003, the Company reduced
non-regulated earnings by $1.1 million in June 2002 to record recalculated
deferred tax obligations and earnings from leveraged lease investments at the
date of enactment of the law. The impact of the tax rate change on the deferred
taxes of the regulated operations is reflected as a regulatory asset for future
recovery in rates.
Results of Operations by Business Segment
- -----------------------------------------
The following is a more detailed discussion of the results of operations of the
Company's regulated and nonregulated businesses. The detailed results of
operations for the regulated businesses and nonregulated businesses 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 business segment, which include primarily information
technology services, are not significant.
Results of Operations of the Regulated Businesses
The Company's regulated operations are comprised of its Gas Utility Services and
Electric Utility Services segments. The Gas Utility Services segment includes
the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services to 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 to primarily
southwestern Indiana, and SIGECO's power generating and power marketing
operations.
Operating Results
- -----------------
The results of regulated operations before certain intersegment eliminations and
reclassifications for the three and nine months ended September 30, 2002 and
2001 are as follows:
Three Months Nine Months
Ended Ended
September 30, September 30,
--------------- -------------------
In millions, except per share amounts 2002 2001 2002 2001
- ------------------------------------- ------ ------ -------- --------
OPERATING REVENUES
Gas utility $ 88.1 $ 96.0 $ 585.0 $ 774.3
Electric utility 190.0 104.3 475.7 287.5
------ ------ -------- --------
Total operating revenues 278.1 200.3 1,060.7 1,061.8
------ ------ -------- --------
COST OF OPERATING REVENUES
Cost of gas 45.6 51.2 358.2 550.1
Fuel for electric generation 22.9 21.1 59.7 56.9
Purchased electric energy 92.5 22.6 239.3 69.4
------ ------ -------- --------
Total cost of operating revenues 161.0 94.9 657.2 676.4
------ ------ -------- --------
TOTAL OPERATING MARGIN 117.1 105.4 403.5 385.4
OPERATING EXPENSES
Other operating 53.3 55.0 164.4 177.8
Merger, integration, & other costs - 1.4 - 2.1
Restructuring costs - 1.2 - 12.0
Depreciation & amortization 24.2 24.6 71.7 74.1
Income tax 4.7 0.7 30.6 11.2
Taxes other than income taxes 9.7 8.6 37.8 38.4
------ ------ -------- --------
Total operating expenses 91.9 91.5 304.5 315.6
------ ------ -------- --------
OPERATING INCOME 25.2 13.9 99.0 69.8
OTHER INCOME
Equity in earnings of unconsolidated
affiliates (0.4) - (1.4) -
Other - net 0.6 1.4 10.7 1.6
------ ------ -------- --------
Total other income 0.2 1.4 9.3 1.6
------ ------ -------- --------
Interest expense 16.5 15.6 49.7 52.3
Preferred dividend requirement
of subsidiary - 0.2 - 0.7
------ ------ -------- --------
Income (loss) before cumulative effect of
change in accounting principle 8.9 (0.5) 58.6 18.4
------ ------ -------- --------
Cumulative effect of change in accounting
principle - net of tax - - - 3.9
------ ------ -------- --------
NET INCOME (LOSS), AS REPORTED $ 8.9 $ (0.5) $ 58.6 $ 22.3
------ ------ -------- --------
Restructuring costs - net of tax - 0.7 - 7.4
Merger & integration costs - net of tax - 2.5 - 6.5
Cumulative effect of change in accounting
principle - net of tax - - - (3.9)
------ ------ -------- --------
NET INCOME (LOSS) BEFORE
NONRECURRING ITEMS $ 8.9 $ 2.7 $ 58.6 $ 32.3
====== ====== ======== ========
EARNINGS (LOSS) PER SHARE,
AS REPORTED $ 0.13 $(0.01) $ 0.87 $ 0.34
Restructuring costs - 0.01 - 0.11
Merger & integration costs - 0.04 - 0.10
Cumulative effect of change in
accounting principle - - - (0.06)
------ ------ -------- --------
EARNINGS (LOSS) PER SHARE
BEFORE NONRECURRING ITEMS $ 0.13 $ 0.04 $ 0.87 $ 0.49
====== ====== ======== ========
Regulated utility operations contributed net income of $58.6 million, or $0.87
per share, for the nine months ended September 30, 2002 compared to $22.3
million, or $0.34 per share, for the same period in 2001. In addition to
completion of merger and restructuring activities and related costs, the
nine-month period increase of $36.3 million, or $0.53 per share, was primarily
the result of improved margins and lower operations and maintenance costs. These
resulted from a return to lower gas prices and the related reduction in costs
incurred in 2001, favorable cooling weather during the second and third
quarters, and merger synergies. The accrual of carrying costs on the Company's
demand side management programs consistent with an existing IURC rate order also
contributed. These favorable impacts were offset somewhat by the effects of warm
weather during the heating season.
For the three months ended September 30, 2002, regulated utility operations
contributed net income of $8.9 million, or $0.13 per share, compared to a net
loss of $0.5 million, or $0.01 per share for the same period in 2001. The
results for regulated operations increased primarily due to increased margins,
partly reflecting favorable cooling weather. The completion of merger and
restructuring activities and related costs in 2001 also contributed.
Gas Utility Margin
Gas Utility margin for the three months ended September 30, 2002 of $42.5
million decreased $2.3 million, or 5%, compared to 2001. The decrease is
primarily due to fluctuations in unaccounted for gas and warmer weather.
Gas Utility margin for the nine months ended September 30, 2002 of $226.8
million increased $2.6 million, or 1%. The increase is primarily due to rate
recovery of excise taxes in Ohio effective July 1, 2001, an increase in the PIPP
rider and customer growth. These favorable impacts were offset somewhat by
warmer weather compared to the prior year during the heating season, customer
conservation, and fluctuations in unaccounted for gas. The effects of warmer
weather during heating periods and customer conservation resulted in an overall
2% decrease in total throughput to 139.9 MMDth in 2002 from 142.3 MMDth in 2001.
Total cost of gas sold was $358.2 million for the nine months ended September
30, 2002 and $550.1 million in 2001. Total cost of gas sold decreased $191.9
million, or 35%, during 2002 compared to 2001, primarily due to a return to
lower gas prices. The total average cost per dekatherm of gas purchased for the
nine months ended September 30, 2002 was $4.38 compared to $6.46 for the same
period in 2001.
Electric Utility Margin
Electric Utility margin for the three and nine months ended September 30, 2002
and 2001 increased $14.0 million, or 23%, and $15.5 million, or 10%,
respectively. The increases result primarily from the effect on retail sales of
cooling weather considerably warmer than the prior year. Weather in 2002 was 31%
warmer for the quarter and 23% warmer for the nine-month period when compared to
2001. For the nine-month period, weather was 22% warmer than normal. In addition
to weather, both the quarter and the nine-month period were positively affected
by a cash return on NOx compliance expenditures pursuant to a rate recovery
rider approved by the IURC in August 2001. The year-to-date period, however, was
negatively affected by decreased margin from power marketing activities.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to optimize the return
on these key assets. The contracts entered into are primarily short-term
purchase and sale transactions that expose the Company to limited market risk.
While volumes both sold and purchased in the wholesale market have increased
during 2002, margins have softened this year as a result of reduced price
volatility. As a result of increased activity offset by reduced price
volatility, margin from power marketing activities decreased $2.9 million for
the year-to-date period. For the quarter, power marketing activities increased
margin by $0.5 million.
Utility Operating Expenses
- --------------------------
Utility Other Operating
Utility other operating expenses decreased $1.7 million for the three months
ended September 30, 2002 and decreased $13.4 million for the nine months ended
September 30, 2002 when compared to the prior year periods. The decreases result
primarily from lower charges for the use of corporate assets related to those
assets which had useful lives shortened as a result of the merger. Also
contributing to the decrease for the nine-month period are merger synergies and
the timing of maintenance expenditures.
Utility Depreciation & Amortization
Utility depreciation and amortization decreased $0.4 million for the three
months ended September 30, 2002 and decreased $2.4 million for the nine months
ended September 30, 2002 when compared to the prior year periods. The decreases
result from the discontinuance of goodwill amortization as required by SFAS 142,
offset somewhat by depreciation of plant additions.
Utility Income Tax Expense
Federal and state income taxes related to utility operations increased $4.0
million for the three months ended September 30, 2002 and increased $19.4
million for the nine months ended September 30, 2002 when compared to the prior
year periods. The increases result principally from higher pre-tax earnings.
Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes increased $1.1 million for the three
months ended September 30, 2002 and decreased $0.6 million for the nine months
ended September 30, 2002 when compared to the prior year periods. The increase
during the quarter is attributable to greater Electric Utility revenues that are
subject to gross receipts tax than in the prior period. For the nine-month
period, the decrease is attributable to a decrease in gross receipts and excise
taxes as a result of lower Gas Utility revenues due to lower gas prices, offset
somewhat by increased Electric Utility revenues subject to gross receipts tax.
Utility Other Income, Net
- -------------------------
Utility other income, net decreased $0.8 million for the quarter and increased
$9.1 million for the nine-month period when compared to the prior year periods.
The decrease in the quarter is attributable to changes in value of investments
that fund deferred compensation arrangements. The increase for the nine-month
period is attributable to the accrual of $5.2 million in carrying costs for
demand side management programs not currently in rates pursuant to an existing
IURC rate order and $1.8 million from the sale of excess emission allowances and
other assets. In addition, the nine-month period is further affected by 2001
contributions made to low income heating assistance programs to assist customers
with their increased utility bills reflecting higher gas costs.
Utility Interest Expense
- ------------------------
Utility interest expense increased $0.9 million for the three months ended
September 30, 2002 and decreased $2.6 million for the nine months ended
September 30, 2002 when compared to the prior year periods. The three-month
period increase results from more borrowings outstanding at higher average
rates. The nine-month period decrease is attributable to consistent outstanding
borrowings at lower average interest rates.
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 United States Environmental
Protection Agency (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 1998 and 1999.
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.
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. 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 September 30, 2002,
$53.5 million has been expended. 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 October 22, 2002,
the Company filed a settlement agreement with the IURC that has been entered
into with the Indiana Office of Utility Consumer Counselor and an industrial
intervenor group relating to the ongoing NOx project. The agreement, if approved
by the IURC, will authorize additional capital cost investment 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. A hearing is scheduled for November 15, 2002 to consider the
agreement. The settlement establishes a fixed return of 8 percent on the capital
investment.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
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. 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
compliant. 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 March 31, 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 expert 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 June of 2002, the Company received a request from the IDEM concerning
information on any manufactured gas plant sites which the Company has not
enrolled in IDEM's Voluntary Remediation Program, specifically five sites which
were owned and/or operated by SIGECO. Preliminary site investigations conducted
by SIGECO in the mid-1990's confirmed that based upon the conditions known at
the time, the sites posed no risk to human health or the environment.
Results of Nonregulated Operations
The Company is 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, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates Internal Revenue Service (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 investments in other businesses that
invest in energy-related opportunities and provides utility services, municipal
broadband consulting, retail, and real estate and leveraged lease investments.
Operating Results
- -----------------
The results of nonregulated operations before certain intersegment eliminations
and reclassifications for the three and nine months ended September 30, 2002 and
2001 are as follows:
Three Months Nine Months
Ended Ended
September 30, September 30,
--------------- -----------------
In millions, except per share amounts 2002 2001 2002 2001
------ ------- ------- -------
Energy services & other revenues $ 26.4 $ 156.4 $ 265.9 $ 611.9
Cost of energy services & other 16.4 143.7 234.9 582.5
------ ------- ------- -------
TOTAL OPERATING MARGIN 10.0 12.7 31.0 29.4
Intersegment revenues, net of costs 0.6 0.4 2.2 1.4
Operating expenses 8.3 9.9 27.3 25.1
Restructuring costs - 1.4 - 2.0
------ ------- ------- -------
OPERATING INCOME 2.3 1.8 5.9 3.7
------ ------- ------- -------
Other income:
Equity in earnings of unconsolidated
affiliates 2.1 4.9 9.2 15.0
Other - net 1.8 2.0 3.7 9.6
------ ------- ------- -------
Total other income 3.9 6.9 12.9 24.6
------ ------- ------- -------
Interest expense 1.9 2.8 6.4 9.2
------ ------- ------- -------
INCOME BEFORE TAXES 4.3 5.9 12.4 19.1
------ ------- ------- -------
Income taxes (1.8) (1.1) (2.5) (0.3)
Minority interest in subsidiary 0.3 1.0 0.1 0.8
------ ------- ------- -------
INCOME BEFORE EXTRAORDINARY LOSS 5.8 6.0 14.8 18.6
------ ------- ------- -------
Extraordinary loss - net of tax - - - 7.7
------ ------- ------- -------
NET INCOME, AS REPORTED $ 5.8 $ 6.0 $ 14.8 $ 10.9
------ ------- ------- -------
Restructuring costs - net of tax - 0.9 - 1.3
Extraordinary loss - net of tax - - - 7.7
------ ------- ------- -------
NET INCOME BEFORE NONRECURRING
ITEMS $ 5.8 $ 6.9 $ 14.8 $ 19.9
====== ======= ======= =======
EARNINGS PER SHARE, AS REPORTED $ 0.09 $ 0.09 $ 0.22 $ 0.16
Restructuring costs - 0.01 - 0.02
Extraordinary loss - - - 0.12
------ ------- ------- -------
EARNINGS PER SHARE BEFORE
NONRECURRING ITEMS $ 0.09 $ 0.10 $ 0.22 $ 0.30
====== ======= ======= =======
For the three months ended September 30, 2002, earnings from nonregulated
operations decreased $0.2 million, and for the nine months ended September 30,
2002 increased $3.9 million, or $0.06 per share. Earnings before these
nonrecurring charges incurred during 2001 decreased $1.1 million for the quarter
and $5.1 million for the nine-month period.
The decreases are attributable to gains recognized upon sale of investments by
an unconsolidated affiliate in the first and third quarters of 2001, lower
interest and leveraged lease income resulting from a divestiture of notes
receivable and leveraged lease investments in the second and fourth quarters of
2001, and decreased performance contracting earnings. In addition, the
nine-month period was negatively affected by a change in Indiana corporate
income tax laws enacted in June 2002, which required the recalculation of
deferred tax obligations and earnings from leveraged lease investments at the
date of enactment of the law. However, the decrease for the nine-month period
was somewhat offset by increased earnings from natural gas marketing and coal
mining operations.
In February 2002, Vectren announced its intention to integrate the operations of
its wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance
Energy, LLC, an equity method affiliate. SES provides natural gas and related
services to SIGECO and others. Effective June 1, 2002, the integration was
completed. In exchange for the contribution of SES' net assets totaling $19.2
million, including cash of $2.0 million, 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. 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.
Energy Services & Other Revenues
- --------------------------------
Revenues from Vectren's non-utility operations (primarily the operating
companies of its Energy Marketing and Services and Coal Mining groups) for the
three and nine months ended September 30, 2002 decreased $130.0 million and
$346.0 million, respectively. Prior to June 2002, revenues were primarily
attributable to Energy Marketing and Services gas marketing operations. The
significant decreases are primarily attributable to lower natural gas prices
prior to June 2002 and the exclusion of SES's revenues since June 2002.
Costs of Energy Services & Other
- --------------------------------
Cost of energy services and other for the three and nine months ended September
30, 2002 decreased $127.3 million and $347.6 million, respectively when compared
to the prior year. These costs are primarily the cost of natural gas purchased
for resale by Energy Marketing and Services' gas marketing operations. The
decreases are primarily due to lower purchased gas costs prior to June 2002 and
the exclusion of SES's gas costs since June 2002.
Nonregulated Margin
- -------------------
Margin from nonregulated operations for the three and nine months ended
September 30, 2002 was $10.0 million and $31.0 million, respectively. Excluding
SES's operations, margins decreased $0.7 million for the quarter and increased
$1.8 million for the nine-month period. The decrease for the quarter results
primarily from lower performance contracting sales. The quarter decrease was
offset by increases in margin from coal mining operations and municipal
broadband construction and consulting operations. The nine-month period increase
primarily results from increased coal mining operations, offset by the decreased
performance contracting margin experienced during the quarter. Coal mining
capacity increased in mid 2001 when the Company's second mine began operations.
During 2002, coal mining operations have increased margin by $0.4 million for
the quarter and $3.4 million for the nine-month period.
Nonregulated Operating Expenses
- -------------------------------
Nonregulated operating expenses consist of other operating expenses,
depreciation and amortization, and taxes other than income taxes. Excluding
SES's operations, for the three months ended September 30, 2002, nonregulated
operating expenses were comparable to the prior year, and for the nine-month
period increased $4.7 million. The increase in the nine-month period is
principally due to amortization of mine development costs and start-up costs for
retail operations in the Other Business Group.
Nonregulated Other Income
- -------------------------
Equity in Earnings of Unconsolidated Affiliates
For the three and nine months ended September 30, 2002, earnings from
unconsolidated affiliates decreased $2.8 million and $5.8 million, respectively,
when compared to the prior year periods. The decreases result from 2001 first
and third quarter gains recognized upon sale of investments by an unconsolidated
affiliate that invests in energy-related opportunities and additional losses
incurred by Pace Carbon Synfuels, LP (an investment that manufactures
synthetic-based fuels and qualifies for Internal Revenue Code Section 29 income
tax credits). These decreases were somewhat offset by increased earnings from
Energy Marketing and Services' investment in ProLiance.
Nonregulated Other - Net
For the three and nine months ended September 30, 2002, nonregulated other - net
decreased $ 0.2 million and $5.9 million, respectively, when compared to the
prior year periods. The decreases result primarily from lower interest and
leveraged lease income resulting from a divestiture of notes receivable and
leveraged lease investments in the second and fourth quarters of 2001.
Nonregulated Interest Expense
- -----------------------------
For the three and nine months ended September 30, 2002, interest expense related
to nonregulated operations has decreased $0.9 million and $2.8 million,
respectively. The decrease is due primarily to lower interest rates on
outstanding short-term borrowings.
Nonregulated Income Tax Expense
- -------------------------------
For the three and nine months ended September 30, 2002, Federal and state income
taxes related to nonregulated operations decreased $0.7 million and $2.2
million, respectively, when compared to the prior year periods. The decreases
result from lower pre-tax earnings and a lower effective tax rate, offset by the
recalculation of deferred tax liabilities at a newly enacted state rate. The
effective tax rate is lower in 2002 primarily due to the utilization of tax
credits, primarily Internal Revenue Code Section 29 income tax credits generated
from the Company's investment in Pace Carbon Synfuels, LP.
Other Operating Matters
- -----------------------
ProLiance Energy, LLC
- ---------------------
ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), began providing
natural gas and related services to Indiana Gas, Citizens Gas, and others in
April 1996. ProLiance also provides services to the Ohio operations and began
providing service to SIGECO in 2002. ProLiance's primary business is optimizing
the gas portfolios of utilities and providing services to large end use
customers.
Regulatory Matters
The sale of gas and provision of other services to Indiana Gas by ProLiance is
subject to regulatory review through the quarterly gas cost adjustment (GCA)
process administered by the IURC. The sale of gas and provision of other
services to the Ohio operations by ProLiance is subject to regulatory review
through the quarterly gas cost recovery (GCR) process administered by the PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility. The
IURC's decision reflected the significant gas cost savings to customers obtained
through ProLiance's services and suggested that all material provisions of the
agreements between ProLiance and the utilities were reasonable. Nevertheless,
with respect to the pricing of gas commodity purchased from ProLiance, the price
paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in the pending, consolidated GCA proceeding involving Indiana
Gas and Citizens Gas.
In 2001, the IURC commenced processing the GCA proceeding regarding the three
pricing issues. The IURC indicated that it would consider the prospective
relationship of ProLiance with the utilities in this proceeding. On June 4,
2002, Indiana Gas and Citizens Gas, together with the Office of Utility Consumer
Counselor and other consumer parties, entered into and filed with the IURC a
settlement setting forth the terms for resolution of all pending regulatory
issues related to ProLiance. On July 23, 2002, the IURC approved the settlement
filed by the parties. The GCA proceeding has been concluded and new supply
agreements between Indiana Gas, SIGECO, Citizens Gas, and ProLiance have been
approved and extended through March 31, 2007. At September 30, 2002 and December
31, 2001, the Company has reserved approximately $4.4 million and $3.2 million,
respectively, of ProLiance's after tax earnings for exposure from this GCA
proceeding which approximates the impact of the settlement for past services
provided to Indiana Gas by ProLiance. The Company expects refunds to retail
customers to be applied to the reserve in December 2002.
In addition to the above, the IURC order also provides that:
|X| A portion of the utilities' natural gas will be purchased through a
gas cost incentive mechanism that shares price risk and reward between
the utilities and customers;
|X| Beginning in 2004, ProLiance will provide the utilities with an
interstate pipeline transport and storage service price discount, thus
providing additional savings to customers;
|X| As ProLiance continues to provide the utilities with its supply
services, Citizens and Vectren will together annually provide an
additional $2 million per year in customer benefits in 2003, 2004 and
2005; and
|X| In 2006, the utilities will conduct a competitive bidding process for
provision of gas supply services commencing in 2007. ProLiance is
authorized to participate in the competitive bidding process.
Pre-tax income of $4.2 million and $2.8 million was recognized as ProLiance's
contribution to earnings for the three months ended September 30, 2002 and 2001,
respectively. Pre-tax income of $15.0 million and $12.4 million was recognized
as ProLiance's contribution to earnings for the nine months ended September 30,
2002 and 2001, respectively. Earnings recognized from ProLiance are included in
equity in earnings of unconsolidated affiliates. Earnings have increased due to
normal growth in operations and Vectren's contribution of SES's operations.
Utilicom Networks, LLC
- ----------------------
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including analog and digital
cable television, high-speed Internet, and advanced local and long distance
phone services. The Company has a minority equity interest and convertible
subordinated debt investment in Utilicom. The Company also has a minority
interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to
hold interests in SIGECOM, LLC (SIGECOM). The Company accounts for its
investments in Utilicom and Holdings on the cost method. SIGECOM provides
broadband services to the greater Evansville, Indiana, area. Utilicom also plans
to provide broadband services to the greater Indianapolis, Indiana, and Dayton,
Ohio, markets.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is 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 are still committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded.
Franchising agreements have been extended in both locations.
Financial Condition
-------------------
The Company's equity capitalization objective is 40-50% of total capitalization.
This objective may have varied, and will vary, depending on particular business
opportunities and seasonal factors that affect the Company's operation. The
Company's equity component was 46% and 45% of total capitalization, including
current maturities of long-term debt and long-term debt subject to tender, at
September 30, 2002 and December 31, 2001, respectively.
Short-term cash working capital is required primarily to finance customer
accounts receivable, unbilled utility revenues resulting from cycle billing, gas
in underground storage, prepaid gas delivery services, capital expenditures, and
investments until permanently financed.
The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds; however, additional
financing may be required in future years due to significant capital
expenditures for NOx compliance equipment at SIGECO.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
March 31, 2002 are A-/A2 as rated by Standard and Poor's and Moody's,
respectively. SIGECO's credit ratings on outstanding secured debt at March 31,
2002 are A-/A1. VUHI's commercial paper has a credit rating of A-2/P-1. Vectren
Capital Corp.'s senior unsecured debt is rated BBB+/Baa2. On August 27, 2002,
Moody's Investor Services issued a press release indicating these ratings are
under review for a possible downgrade. Moody's raised several concerns including
weaker credit and fixed charge coverage measures, resulting from the prior
integration and restructuring costs and warm winter of 2001 and 2002; the
regulatory treatment of the significant NOx environmental expenditures and the
ratings triggers in $113.0 million of Vectren Capital Corp debt discussed below.
The Company continues to work with Moody's to address these and other items
including the favorable NOx settlement and strategies around the triggers.
Cash Flow From Operations
- -------------------------
The Company's primary source of liquidity to fund working capital requirements
has been cash generated from operations, which totaled $273.2 million and $151.3
million for the nine months ended September 30, 2002 and 2001, respectively.
Cash flow from operations increased during the nine months ended September 30,
2002 compared to 2001 by $121.9 million due primarily to favorable changes in
working capital accounts due to a return to lower gas prices and increased
earnings before non-cash charges.
Financing Activities
- --------------------
Sources & Uses of Liquidity
- ---------------------------
At September 30, 2002, the Company had $510.0 million of short-term borrowing
capacity through lines of credit and commercial paper programs, including $330.0
million for its regulated operations and $180.0 million for its wholly-owned
nonregulated and corporate operations, of which $158.3 million was available for
regulated operations and $31.7 million was available for nonregulated and
corporate operations. At September 30, 2002, credit available for nonregulated
operations is reduced by outstanding letters of credit totaling $7.0 million.
During the nine months ended September 30, 2002, $1.3 million of long-term debt
was paid as scheduled, and put provisions totaling $5.0 million were exercised.
Other put provisions on long-term debt totaling $6.5 million expired unexercised
and have been reclassified as long-term debt.
At September, 2002, $113.0 million of Vectren Capital 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. Ratings triggers on Vectren
Capital Corp.'s bank loans and VUHI's commercial paper back up facility existing
at December 31, 2001 were removed as facilities were renewed during 2002. As
previously discussed under Financial Condition above, Indiana Gas and SIGECO
ratings are under review by Moody's for possible downgrade. However, the
existing Moody's ratings of A2 and A1, respectively, are well above the ratings
trigger. The Company is currently exploring additional strategies regarding the
ratings triggers including further expanding unutilized capacity under its
nonregulated short-term borrowing facilities for additional liquidity
protection.
Financing Cash Flow
Cash flow required for financing activities of $122.8 million for the nine
months ended September 30, 2002 includes $70.0 million of reductions in net
borrowings and $53.7 million in common stock dividends. In the prior year,
$129.4 million of common stock was issued and used to repay short term
borrowings.
Other Financing Transactions
In January 2002, the Company redeemed 1,160 shares of SIGECO's 8.5% preferred
stock per its stated terms of $100 per share, plus accrued and unpaid dividends.
Prior to the redemption, there were 4,597 shares outstanding.
Capital Expenditures, Other Investment Activities, & Guarantees
- ---------------------------------------------------------------
Cash required for investing activities of $159.0 million for the nine months
ended September 30, 2002 includes $150.2 million of requirements for capital
expenditures. Investing activities for the nine months ended September 30, 2001
were $110.6 million. The $48.4 million increase occurring in 2002 is principally
the result of more expenditures for utility plant and the sale of leveraged
lease investments in 2001.
Planned Capital Expenditures
- ----------------------------
New construction, normal system maintenance and improvements, and information
technology investments needed to provide service to a growing regulated and
nonregulated customer base will continue to require substantial expenditures.
Investments in nonregulated unconsolidated affiliates and company-wide capital
expenditures for the remainder of 2002 are estimated at $67.7 million. Estimated
investments in nonregulated unconsolidated affiliates and company-wide capital
expenditures for 2003 are estimated at $249.5 million.
Guarantees
- ----------
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees include debt guarantees and performance guarantees, including the
debt of and performance of energy efficiency products installed by affiliated
companies. The Company estimates these guarantees totaled approximately $90
million at September 30, 2002. The Company's most significant guarantee totaling
$59.8 million represents two-thirds of Energy Systems Group, LLC's (ESG) surety
bonds, performance and energy savings guarantees. ESG is a two-thirds owned
consolidated subsidiary. 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 September 30, 2002, the Company has not been called upon to
satisfy any obligations pursuant to the guarantees.
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 included, among others, the following:
|X| 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.
|X| Increased competition in the energy environment including effects of
industry restructuring and unbundling.
|X| 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.
|X| 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 natural gas
transmission, gathering and processing, and similar entities with
regulatory oversight.
|X| Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
|X| 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.
|X| Availability or cost of capital, resulting from changes in the
Company, including its security ratings, changes in interest rates,
and/or changes in market perceptions of the utility industry and other
energy-related industries.
|X| Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages.
|X| Legal and regulatory delays and other obstacles associated with
mergers, acquisitions, and investments in joint ventures.
|X| 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.
|X| 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 market 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.
Commodity Price Risk
- --------------------
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electric energy for its retail
customers due to current Indiana and Ohio regulations, which subject to
compliance with applicable state regulations, allow for recovery of such
purchases through natural gas and fuel cost adjustment mechanisms.
The Company does engage in limited wholesale power marketing operations and
other operations involving the purchase and sale of commodities that may expose
it to commodity price risk associated with fluctuating electric power, natural
gas, and coal commodity prices. Other commodity operations include nonregulated
retail gas supply operations in states that allow for choice.
The Company's wholesale power marketing operations manage the utilization of its
available electric generating capacity. The Company's other operations that
involve the purchase and sale of commodities buy and sell natural gas and coal
to meet customer demands. These operations enter into forward and option
contracts that commit the Company to purchase and sell commodities in the
future.
As a result of the integration of the Company's wholly owned subsidiary, SIGCORP
Energy Services, LLC, into ProLiance Energy, LLC, a joint venture accounted for
using the equity method, all natural gas marketing is now conducted by
ProLiance.
Commodity price risk results from forward sale and option contracts that commit
the Company to deliver commodities on specified future dates. Power marketing
uses planned unutilized generation capability and forward purchase contracts to
protect certain sales transactions from unanticipated fluctuations in the price
of electric power, and periodically, will use derivative financial instruments
to protect its interests from unplanned outages and shifts in demand.
Additionally, other commodity activities use stored inventory and forward
purchase contracts to protect certain sales transactions from unanticipated
fluctuations in commodity prices.
Open positions in terms of price, volume and specified delivery points may occur
to a limited extent and are managed using methods described above and frequent
management reporting.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to optimize the return
on these key assets. The contracts entered into are primarily short-term
purchase and sale contracts that expose the Company to limited market risk.
During 2002, the Company has increased its activity in the wholesale market.
With the exception of those contracts subject to the normal purchase and sale
exclusion, commodity contracts are accounted for at market value. As of
September 30, 2002, contracts had no net asset value compared to a net asset
value of $3.2 million at December 31, 2001. The Company has determined these
power marketing contracts are derivatives within the scope of SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities."
Power marketing contracts at September 30, 2002 totaled $7.7 million of
prepayments and other current assets and $7.7 million of accrued liabilities,
compared to $5.2 million of prepayments and other current assets and $2.0
million of accrued liabilities at December 31, 2001. For the three months ended
September 30, 2002 and 2001, the change in the net value of these contracts
includes an unrealized gain of $0.2 million and an unrealized loss of $0.9
million, respectively. For the nine months ended September 30, 2002 and 2001,
the change in the net value of these contracts includes unrealized losses of
$3.0 million and $3.3 million, respectively. Including these unrealized changes
in fair value, overall margin (revenue net of purchased power) from power
marketing operations for the three months ended September 30, 2002 and 2001 was
$4.6 million and $4.1 million, respectively, and for the nine months ended
September 30, 2002 and 2001 was $8.0 million and $10.9 million, respectively.
Market risk is measured by management as the potential impact on pre-tax
earnings resulting from a 10% adverse change in the forward price of commodity
prices on market sensitive financial instruments (all contracts not expected to
be settled by physical receipt or delivery). For the three and nine months ended
September 30, 2002, a 10% adverse change in the forward prices of electricity on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $0.0 million and $1.4 million, respectively. For the three and
nine months ended September 30, 2001, a 10% adverse change in the forward prices
of electricity on market sensitive financial instruments would have decreased
pre-tax earnings by approximately $0.6 million and $2.0 million, respectively.
Commodity Price Risk from Unconsolidated Affiliate
- --------------------------------------------------
Commodity price risk from an unconsolidated affiliate is not significantly
different from the information as set forth in Item 7A. Quantitative and
Qualitative Disclosures About Market Risk included in the Vectren 2001 Form 10-K
and is therefore not presented herein.
Interest Rate Risk
- ------------------
Interest rate risk is not significantly different from the information as set
forth in Item 7A. Quantitative and Qualitative Disclosures About Market Risk
included in the Vectren 2001 Form 10-K and is therefore not presented herein.
Other Risks
- -----------
By using forward purchase contracts and derivative financial instruments to
manage risk, the Company exposes itself to counter-party credit risk and market
risk. The Company manages this exposure to counter-party credit risk by entering
into contracts with companies that can be reasonably expected to fully perform
under the terms of the contract. Counter-party credit risk is monitored
regularly and positions are adjusted appropriately to manage risk. Further,
tools such as netting arrangements and requests for collateral are also used to
manage credit risk. The Company attempts to manage exposure to market risk
associated with commodity contracts and interest rates by establishing and
monitoring parameters that limit the types and degree of market risk that may be
undertaken.
The Company's customer receivables from gas and electric sales and gas
transportation services are primarily derived from a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its receivables by
continually reviewing creditworthiness and requests cash deposits based on that
review. Credit risk associated with certain investments is also managed by a
review of creditworthiness and receipt of collateral.
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 or 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 timely basis material information relating to the
Company required to be disclosed by the Company in its Exchange Act reports.
Disclosure controls and procedures, as defined by the Securities Exchange Act of
1934 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 Securities and
Exchange Act of 1934 (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.
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. No material weaknesses or other
significant deficiencies in the design of internal control were noted by the
Company during the most recent disclosure control and procedure evaluation and
through the filing of this Form 10-Q.
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 and regulatory proceedings arising in the
normal course of business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position or results of operations. See Note 8
regarding environmental matters and Note 7 regarding ProLiance Energy, LLC.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10.1 Vectren Corporation Retirement Savings Plan (Amended and Restated
Effective January 1, 2002). (Filed herewith.)
(b) Reports On Form 8-K During The Last Calendar Quarter
On July 23, 2002, 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 for the three, six and twelve
month periods ended June 30, 2002. The financial information was released to the
public through this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - Second Quarter 2002 Vectren
Corporation Earnings
99.2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
On July 25, 2002, Vectren Corporation filed an amendment to current report on
Form 8-K, originally filed on April 25, 2002, with respect to the approval of an
agreement by the Indiana Utility Regulatory Commission setting forth the
settlement of numerous pending issues related to ProLiance Energy, LLC
Item 5. Other Events
Item 7. Exhibits
99-1 - Press Release - ProLiance Settlement Approved,
Customers Save Millions, Utilities Receive Certainty
On August 14, 2002 Vectren Corporation filed a current report on Form 8-K with
respect to the Principal Executive Officer, Niel C. Ellerbrook, and the
Principal Financial Officer, Jerome A. Benkert, Jr., of Vectren Corporation
submitting to the Securities and Exchange Commission sworn statements pursuant
to Securities and Exchange Commission Order 4-460.
Item 9. Regulation FD Disclosure.
Item 7. Exhibits.
99-1 - Statement Under Oath of Principal Executive Officer
dated August 14, 2002
99-2 - Statement Under Oath of Principal Financial Officer
dated August 14, 2002
On August 30, 2002, Vectren Corporation filed a Current Report on Form 8-K with
respect to the issuance of a press release by Moody's Investor Services
regarding the potential downgrade of credit ratings on various debt instruments
issued by certain of Vectren Corporation's (Vectren) wholly owned subsidiaries.
Item 5. Other Events
Item 7. Exhibits.
99-1 - Moody's Press Release.
99-2 - Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform
Act of 1995
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
November 13, 2002 /s/Jerome A. Benkert, Jr.
----------------------------
Jerome A. Benkert, Jr.
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/M. Susan Hardwick
----------------------------
M. Susan Hardwick
Vice President and 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: November 13, 2002
/s/ Niel C. Ellerbrook
--------------------------------
Niel C. Ellerbrook
Chairman and 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: November 13, 2002
/s/ Jerome A. Benkert, Jr.
---------------------------------------
Jerome A. Benkert, Jr.
Executive Vice President and
Chief Executive 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 13th day of November, 2002.
/s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook
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(Signature of Authorized Officer) (Signature of Authorized Officer)
Jerome A. Benkert, Jr. Niel C. Ellerbrook
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(Typed Name) (Typed Name)
Executive Vice President and
Chief Financial Officer Chairman and Chief Executive Officer
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(Title) (Title)