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 June 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 ___________________
Commission file number 1-16739
VECTREN UTILITY HOLDINGS, INC.
(Exact name of registrant as specified in its charter)
INDIANA 35-2104850
- ------------------------------------------ -------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
(Address of principal executive offices and Zip Code)
(812) 491-4000
(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 10 August 1, 2002
- ------------------------------- ------------------ ---------------------
Class Number of shares Date
As of August 1, 2002, all shares outstanding of the Registrant's common stock
were held by Vectren Corporation.
Table of Contents
Item Page
Number Number
PART I. FINANCIAL INFORMATION
1 Financial Statements (Unaudited)
Vectren Utility Holdings, Inc. and Subsidiary Companies
Consolidated Condensed Balance Sheets 1-2
Consolidated Condensed Statements of Income 3
Consolidated Condensed Statements of Cash Flows 4
Notes to Unaudited Consolidated Condensed Financial Statement 5-12
2 Management's Discussion and Analysis of Results of Operations 13-23
And Financial Condition
3 Quantitative and Qualitative Disclosures About Market Risk 24-25
PART II. OTHER INFORMATION
1 Legal Proceedings 26
6 Exhibits and Reports on Form 8-K 26
Signatures 27
Certification Pursuant To 18 U.S.C. Section 1350, 28
As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley Act Of 2002
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,
USEPA means United States Environmental Protection Agency, and
throughput means combined gas sales and gas transportation volumes.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
June 30, December 31,
2002 2001
- ------------------------------------------------- --------- -----------
ASSETS
Utility Plant
Original cost $ 2,966.4 $ 2,903.2
Less: Accumulated depreciation & amortization 1,346.6 1,308.2
-------- --------
Net utility plant 1,619.8 1,595.0
-------- --------
Current Assets
Cash & cash equivalents 8.6 7.2
Accounts receivable-less reserves of $4.1 &
$5.6, respectively 91.9 125.3
Receivables from other Vectren companies 7.3 58.2
Accrued unbilled revenues 28.5 78.3
Inventories 39.1 55.3
Recoverable fuel & natural gas costs 50.9 76.5
Prepayments & other current assets 79.0 95.8
-------- --------
Total current assets 305.3 496.6
-------- --------
Investments in unconsolidated affiliates 3.7 4.0
Other investments 12.2 12.2
Non-utility property-net 5.7 6.3
Goodwill-net 199.3 198.6
Regulatory assets 80.7 61.4
Other assets 19.3 17.3
-------- --------
TOTAL ASSETS $ 2,246.0 $ 2,391.4
======== ========
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
June 30, December 31,
2002 2001
- ---------------------------------------------------- --------- -----------
LIABILITIES & SHAREHOLDER'S EQUITY
Capitalization
Common shareholder's equity
Common stock (no par value) $ 385.7 $ 385.7
Retained earnings 342.9 329.0
Accumulated other comprehensive income (1.7) (1.7)
-------- --------
Total common shareholder's equity 726.9 713.0
-------- --------
Cumulative Redeemable Preferred Stock of Subsidiary 0.3 0.5
Long-term debt- net of current maturities and debt
subject to tender 890.3 900.9
-------- --------
Total capitalization 1,617.5 1,614.4
-------- --------
Commitments & Contingencies (Notes 6-8)
Current Liabilities
Accounts payable 54.8 79.0
Accounts payable to affiliated companies 33.4 36.5
Payables to other Vectren companies 18.4 11.5
Accrued liabilities 98.8 97.5
Short-term borrowings 116.2 274.2
Long-term debt subject to tender - 11.5
Current maturities of long-term debt 17.3 1.3
-------- --------
Total current liabilities 338.9 511.5
-------- --------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 193.4 171.8
Deferred credits & other liabilities 96.2 93.7
-------- --------
Total deferred income taxes & other liabilities 289.6 265.5
-------- --------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 2,246.0 $ 2,391.4
======== ========
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited - In millions)
Three Months Six Months
Ended June 30, Ended June 30,
------------------ ------------------
2002 2001 2002 2001
- -------------------------------------- -------- -------- -------- --------
OPERATING REVENUES
Gas revenues $ 139.8 $ 154.6 $ 496.9 $ 678.3
Electric revenues 158.9 95.0 285.7 183.2
------ ------ ------ ------
Total operating revenues 298.7 249.6 782.6 861.5
------ ------ ------ ------
COST OF OPERATING REVENUES
Cost of gas sold 82.2 94.8 312.6 498.9
Fuel for electric generation 19.0 17.8 36.8 35.8
Purchased electric energy 87.0 33.6 146.8 46.8
------ ------ ------ ------
Total cost of operating revenues 188.2 146.2 496.2 581.5
------ ------ ------ ------
TOTAL OPERATING MARGIN 110.5 103.4 286.4 280.0
OPERATING EXPENSES
Other operating 55.3 61.0 111.1 122.8
Merger & integration costs - - - 0.7
Restructuring costs - 10.8 - 10.8
Depreciation & amortization 23.9 24.7 47.5 49.5
Income taxes 3.6 (7.3) 25.9 10.5
Taxes other than income taxes 10.2 10.7 28.1 29.8
------ ------ ------ ------
Total operating expenses 93.0 99.9 212.6 224.1
------ ------ ------ ------
OPERATING INCOME 17.5 3.5 73.8 55.9
Equity in earnings of unconsolidated
affiliates (0.4) - (1.0) -
Other income - net 8.3 1.1 10.1 0.2
Interest expense 16.3 17.2 33.2 36.7
Preferred dividend requirement
of subsidiary - 0.3 - 0.5
------ ------ ------ ------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 9.1 (12.9) 49.7 18.9
------ ------ ------ ------
Cumulative effect of change in accounting
principle - net of tax - - - 3.9
------ ------ ------ ------
NET INCOME (LOSS) $ 9.1 $ (12.9) $ 49.7 $ 22.8
====== ====== ====== ======
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited - In millions)
Six Months Ended
June 30,
--------------------
2002 2001
- ---------------------------------------------------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 49.7 $ 22.8
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 47.5 49.5
Equity in losses of unconsolidated affiliates 1.0 -
Restructuring costs - 10.8
Deferred income taxes & investment tax credits (0.3) 3.0
Net unrealized loss (gain) on derivative
instruments, including cumulative
effect of change in accounting principle 3.1 (3.9)
Other non-cash charges- net (2.2) 9.7
Changes in assets and liabilities:
Accounts receivable, including to Vectren
companies & accrued unbilled revenues 129.5 188.7
Inventories 16.2 35.0
Recoverable fuel & natural gas costs 25.6 (0.6)
Prepayments & other current assets 21.3 2.7
Regulatory assets - (1.2)
Accounts payable, including to Vectren
companies & affiliated companies (18.2) (170.6)
Accrued liabilities (0.7) (35.2)
Other noncurrent assets & liabilities (2.7) (5.0)
------ ------
Total adjustments 220.1 82.9
------ ------
Net cash flows from operating activities 269.8 105.7
------ ------
CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES
Proceeds from additional capital contribution - 129.4
Requirements for:
Dividends on common stock (35.8) (31.3)
Retirement of preferred stock of subsidiary (0.2) (0.2)
Retirement of long-term debt (6.3) (6.8)
Net change in short-term borrowings (158.0) (159.5)
------ ------
Net cash flows (required for)
financing activities (200.3) (68.4)
------ ------
CASH FLOWS (REQUIRED FOR) INVESTING
ACTIVITIES
Proceeds from sale of investments 2.6 -
Capital expenditures (69.7) (36.2)
Unconsolidated affiliate investments (1.0) -
Other investing proceeds - (2.2)
------ ------
Net cash flows (required for) investing
activities (68.1) (38.4)
------ ------
Net increase in cash & cash equivalents 1.4 (1.1)
Cash & cash equivalents at beginning of period 7.2 2.2
------ ------
Cash & cash equivalents at end of period $ 8.6 $ 1.1
====== ======
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Nature of Operations
Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation,
was formed on March 31, 2000 to serve as the intermediate holding company for
Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas
Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana
Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (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.
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 and
SIGCORP. On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16). Therefore, the reorganization of Indiana Gas
and SIGECO into subsidiaries of VUHI has been accounted for as a combination of
entities under common control.
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.
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 June 2002, the EITF reached a final consensus in EITF Issue 02-03 "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that states mark-to-market gains and losses on energy trading contracts
(whether realized or unrealized and whether financially or physically settled)
should be shown net in the income statement and that expanded disclosure of
energy trading activities is required. This consensus is effective for periods
ending after July 15, 2002, with reclassification of prior period amounts
required.
The Company currently accounts for all its power marketing contracts at gross in
the Consolidated Condensed Statements of Income. The Company has reviewed all of
its current power marketing contracts and contracts closed in prior periods and
identified no energy trading contracts subject to EITF 02-03. See Note 9 for
more 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 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, 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 Six Months
Ended June 30, Ended June 30,
---------------- -----------------
In millions 2002 2001 2002 2001
- -------------------------------------- ------ ------- ------- -------
Net income (loss) $ 9.1 $ (12.9) $ 49.7 $ 22.8
Minimum pension liability adjustment
and other- net of tax - (0.1) - (1.0)
----- ------- ------- -------
Total comprehensive income $ 9.1 $ (13.0) $ 49.7 $ 21.8
===== ======= ======= =======
5. Transactions with Other Vectren Companies
Support Services & Purchases
Vectren and certain subsidiaries of Vectren have provided corporate, general and
administrative services to the Company including legal, finance, tax, risk
management, and human resources. The costs have been allocated to the Company
using various allocators, primarily number of employees, number of customers
and/or revenues. Management believes that the allocation methodology is
reasonable and approximates the costs that would have been incurred had the
Company secured those services on a stand-alone basis. For the three months
ended June 30, 2002 and 2001, amounts billed by other wholly owned subsidiaries
of Vectren to the Company were $38.3 million and $29.5 million, respectively.
For the six months ended June 30, 2002 and 2001, amounts billed by other wholly
owned subsidiaries of Vectren to the Company were $73.3 million and $62.4
million, respectively.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates
coal mines from which SIGECO purchases fuel used for electric generation.
Amounts paid for such purchases for the three months ended June 30, 2002 and
2001 were $15.0 million and $9.7 million, respectively. Amounts paid for such
purchases for the six months ended June 30, 2002 and 2001 were $28.2 million and
$20.9 million, respectively.
Cash Management & Borrowing Arrangements
The Company participates in a centralized cash management program with Vectren,
other wholly owned subsidiaries, and banks which permits funding of checks as
they are presented.
Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are
guarantors of VUHI's $325 million commercial paper program, of which $116.2
million is outstanding at June 30, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at June 30, 2002. These guarantees are full and
unconditional and joint and several. VUHI has no significant independent assets
or operations other than the assets and operations of these operating utility
companies.
6. Transactions with Vectren Affiliates
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 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 are 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 April 23,
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 an
agreement in principle setting forth the terms for resolution of all pending
regulatory issues related to ProLiance. The parties submitted for IURC approval
a final settlement on June 4, 2002. On July 23, 2002, the IURC approved the
settlement filed by the parties. Any appeal of the IURC's approval order must be
filed by August 23, 2002. 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 June 30, 2002 and December 31,
2001, the Company has reserved approximately $3.7 million and $3.2 million,
respectively, of ProLiance's after tax earnings for exposure from this GCA
proceeding. All payments to be made pursuant to the settlement will be paid by
Vectren. Therefore, there is no impact to VUHI's earnings as a result of the
final settlement.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
three months ended June 30, 2002 and 2001 totaled $108.7 million and $146.0
million, respectively; and for the six months ended June 30, 2002 and 2001
totaled $236.5 million and $414.4 million, respectively. Amounts owed to
ProLiance at June 30, 2002 and December 31, 2001 for those purchases were $32.5
million and $36.1 million, respectively, and are included in accounts payable to
affiliated companies. Amounts charged by ProLiance for gas supply services are
set forth by supply agreements with each utility.
7. Commitments & Contingencies
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 6 regarding ProLiance Energy, LLC.
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.
The Company has recently filed another proceeding with the IURC to receive
approval of additional capital costs and to obtain approval for recovery of
future operating costs, including depreciation, related to the SCR's through a
rider mechanism. Based on the level of system-wide emissions reductions required
and the control technology utilized to achieve the reductions, the current
estimated construction cost ranges from $240 million to $250 million and is
expected to be expended during the 2001-2006 period. Through June 30, 2002,
$41.0 million has been expended. After the equipment is installed and
operational, related additional annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million.
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.
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 better utilize and
optimize the return on these key assets. The contracts entered into are
primarily "buy-sell" transactions, short-term in nature, and 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 June 30, 2002, contracts had a net asset value of $0.1
million compared to a net asset value of $3.2 million at December 31, 2001. The
Company has determined these energy marketing contracts are derivatives within
the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities."
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, or absent quoted market prices, other valuation techniques.
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 June 30, 2002 totaled $9.7 million of prepayments
and other current assets and $9.6 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. The change in the net value of these contracts
to $0.1 million at June 30, 2002 from $3.2 million at December 31, 2001 resulted
in an unrealized loss of $0.1 million and $3.1 million, respectively, for the
three and six months ended June 30, 2002. For the three and six months ended
June 30, 2001, the Company's power marketing operations resulted in unrealized
losses of $7.9 million and $2.4 million, respectively. Including these
unrealized changes in fair value, overall margin (revenue net of purchased
power) from power marketing operations for the three and six months ended June
30, 2002 was $2.4 million and $3.4 million, respectively, and for the three and
six months ended June 30, 2001 was ($4.6) million and $6.8 million,
respectively.
10. Segment Reporting
There were two operating segments during the three and six months ended June 30,
2002: (1) Gas Utility Services and (2) Electric Utility Services. 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 in nearly two-thirds of Indiana and
west central Ohio. The Electric Utility Services segment includes the operations
of SIGECO's power generating and marketing operations, and electric transmission
and distribution services, which provides electricity to primarily southwestern
Indiana. The following tables provide information about business segments.
Three Months Six Months
Ended June 30, Ended June 30,
--------------------- ------------------
In millions 2002 2001 2002 2001
- --------------------------------- --------- --------- -------- --------
Operating Revenues
Gas Utility Services $ 139.8 $ 154.6 $ 496.9 $ 678.3
Electric Utility Services 158.9 95.0 285.7 183.2
-------- -------- ------- -------
Total operating revenues $ 298.7 $ 249.6 $ 782.6 $ 861.5
======== ======== ======= =======
Net Income (Loss)
Gas Utility Services $ (3.1) $ (16.1) $ 29.8 $ 2.7
Electric Utility Services 12.2 3.2 19.9 20.1
-------- -------- ------- -------
Net income (loss) $ 9.1 $ (12.9) $ 49.7 $ 22.8
======== ======== ======= =======
June 30, December 31,
In millions 2002 2001
- --------------------------------- --------- -----------
Identifiable Assets
Gas Utility Services $ 1,405.0 $ 1,580.2
Electric Utility Services 841.0 811.2
-------- --------
Total identifiable assets $ 2,246.0 $ 2,391.4
======== ========
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Description of the Business
Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation,
was formed on March 31, 2000 to serve as the intermediate holding company for
Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas
Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana
Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (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.
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 and
SIGCORP. On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16). Therefore, the reorganization of Indiana Gas
and SIGECO into subsidiaries of VUHI has been accounted for as a combination of
entities under common control.
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.
Results of Operations
The Company's 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 SIGECO's power supply operations, power
marketing operations, and electric transmission and distribution services that
provide electricity to primarily southwestern Indiana. The results of operations
for the three and six months ended June 30, 2002 and 2001 are as follows:
Three Months Six Months
Ended June 30, Ended June 30,
----------------- ---------------
In millions 2002 2001 2002 2001
- ------------------------------------------- ----- -------- ------ ------
Net income, as reported $ 9.1 $ (12.9) $ 49.7 $ 22.8
Merger and integration costs-net of tax - 1.7 - 4.0
Restructuring costs-net of tax 6.7 6.7
Cumulative effect of change in accounting
principle - net of tax - - - (3.9)
----- ------- ------ ------
Net income before nonrecurring items $ 9.1 $ (4.5) $ 49.7 $ 29.6
===== ======= ====== ======
Net Income
Net income was $9.1 million for the three months ended June 30, 2002 compared to
a net loss of $12.9 million for the same period in 2001. The results for
regulated operations increased due to the accrual of carrying costs on the
Company's demand side management programs consistent with an existing IURC rate
order, merger synergies, increased margin due to favorable weather, and the
completion of merger and restructuring activities and related costs.
Net income was $49.7 million for the six months ended June 30, 2002 compared to
$22.8 million for the same period in 2001. In addition to the increases
affecting the quarterly results, the year-to-date period was favorably impacted
by the return to lower gas prices and the related reduction in costs incurred in
2001. These increases were offset by decreased margins from non-firm wholesale
electric sales and the effects of warm weather during the peak heating season.
New Accounting Principles
EITF 02-03
In June 2002, the EITF reached a final consensus in EITF Issue 02-03 "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that states mark-to-market gains and losses on energy trading contracts
(whether realized or unrealized and whether financially or physically settled)
should be shown net in the income statement and that expanded disclosure of
energy trading activities is required. This consensus is effective for periods
ending after July 15, 2002, with reclassification of prior period amounts
required.
The Company currently accounts for all its power marketing contracts at gross in
the Consolidated Condensed Statements of Income. The Company has reviewed all of
its current power marketing contracts and contracts closed in prior periods and
identified no energy trading contracts subject to EITF 02-03.
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 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, 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.
Significant Fluctuations
Utility Margin
Gas Utility Margin
Gas Utility margin for the three months ended June 30, 2002 was favorably
impacted by rate recovery of excise taxes in Ohio effective July 1, 2001, an
increase in the Ohio Percentage of Income Payment Plan (PIPP) rider, customer
growth, and weather considerably cooler during April and May than in the prior
year. The effects of cooler weather and customer growth resulted in an overall
5% increase in total throughput to 35.5 MMDth in 2002 from 33.7 MMDth in 2001.
However, the timing of the cooler weather and other adjustments offset these
factors, resulting in an overall 3.6% decrease in margin when compared to the
prior year.
Total cost of gas sold was $82.2 million for the three months ended June 30,
2002 and $94.8 million in 2001. Total cost of gas sold decreased $12.6 million,
or 13%, 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 three
months ended June 30, 2002 was $4.44 compared to $6.03 for the same period in
2001.
Gas Utility margin for the six months ended June 30, 2002 of $184.3 million
increased $4.9 million, or 3%, compared to 2001. 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 peak heating season. The
effects of warmer weather during peak heating periods resulted in an overall 3%
decrease in total throughput to 113.4 MMDth in 2002 from 116.4 MMDth in 2001.
Total cost of gas sold was $312.6 million for the six months ended June 30, 2002
and $498.9 million in 2001. Total cost of gas sold decreased $186.3 million, or
37%, 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 six months
ended June 30, 2002 was $4.45 compared to $7.17 for the same period in 2001.
Electric Utility Margin
Electric Utility margin for the three months ended June 30, 2002 of $52.9
million increased $9.3 million, or 21%, from 2001 primarily due to fluctuations
in fair value of derivative contracts. Non-firm wholesale margins in 2001
reflect a $7.9 million reduction due to fair value fluctuations, compared to a
$0.1 million reduction in 2002. The remaining increase, attributable to retail
and firm wholesale sales, results from weather 16% warmer than normal and 10%
warmer than the prior year and a cash return on NOx compliance expenditures
pursuant to a rate recovery rider approved by the IURC in August 2001.
Electric Utility margin for the six months ended June 30, 2002 of $102.1 million
increased $1.5 million, or 1%, from 2001 due to the effects of warmer weather,
offset somewhat by decreases in non-firm wholesale margin.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to better utilize and
optimize the return on these key assets. The contracts entered into are
primarily "buy-sell" transactions, short-term in nature, and expose the Company
to limited market risk. During 2002, the Company has increased its activity in
the wholesale market, as evidenced by increased electric revenues and purchased
power. While volumes both sold and purchased 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, non-firm wholesale power
margins decreased $3.4 million for the year-to-date period.
Operating Expenses
Utility Other Operating
Utility other operating expenses decreased $5.7 million for the three months
ended June 30, 2002 and decreased $11.7 million for the six months ended June
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
decreases are merger synergies, the timing of maintenance expenditures and
increased uncollectible accounts expense in 2001 resulting from high gas costs.
Utility Depreciation & Amortization
Utility depreciation and amortization decreased $0.8 million for the three
months ended June 30, 2002 and decreased $2.0 million for the six months ended
June 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 $10.9
million for the three months ended June 30, 2002 and increased $15.4 million for
the six months ended June 30, 2002 when compared to the prior year periods. The
increases result from higher pre-tax earnings offset somewhat by a small
decrease in the current year effective tax rate.
Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes decreased $0.5 million for the three
months ended June 30, 2002 and decreased $1.7 million for the six months ended
June 30, 2002 when compared to the prior year periods. The decreases result
primarily from a decrease in gross receipts and excises taxes as a result of
lower gas prices and lower volumes in the six-month period.
Other Income-Net
Utility other income, net increased $7.2 million for the three months ended June
30, 2002 and increased $9.9 million for the six months ended June 30, 2002 when
compared to the prior year periods. The increases are 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
six 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.
Interest Expense
Utility interest expense decreased $0.9 million for the three months ended June
30, 2002 and decreased $3.5 million for the six months ended June 30, 2002 when
compared to the prior year periods. The decreases result from lower interest
rates on variable rate debt and lower outstanding balances. The reduced
short-term debt outstanding is due primarily to decreased working capital
requirements resulting from a return to lower gas prices.
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.
The Company has recently filed another proceeding with the IURC to receive
approval of additional capital costs and to obtain approval for recovery of
future operating costs, including depreciation, related to the SCR's through a
rider mechanism. Based on the level of system-wide emissions reductions required
and the control technology utilized to achieve the reductions, the current
estimated construction cost ranges from $240 million to $250 million and is
expected to be expended during the 2001-2006 period. Through June 30, 2002,
$41.0 million has been expended. After the equipment is installed and
operational, related additional annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million.
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.
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.
Regulatory Matters
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.
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 are 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 April 23,
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 an
agreement in principle setting forth the terms for resolution of all pending
regulatory issues related to ProLiance. The parties submitted for IURC approval
a final settlement on June 4, 2002. On July 23, 2002, the IURC approved the
settlement filed by the parties. Any appeal of the IURC's approval order must be
filed by August 23, 2002. 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 June 30, 2002 and December 31,
2001, the Company has reserved approximately $3.7 million and $3.2 million,
respectively, of ProLiance's after tax earnings for exposure from this GCA
proceeding. All payments to be made pursuant to the settlement will be paid by
Vectren. Therefore, there is no impact to VUHI's earnings as a result of the
final settlement.
Financial Condition
The Company's equity capitalization objective is 40-55% 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 44% of total capitalization, including current
maturities of long-term debt and long-term debt subject to tender, at both June
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. Short-term borrowings tend to be
greatest during the summer when accounts receivable and unbilled utility
revenues related to electricity are highest and gas storage facilities are being
refilled.
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 expenditure
for NOx compliance equipment at SIGECO.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
June 30, 2002 are A-/A2 as rated by Standard and Poor's and Moody's,
respectively. SIGECO's credit ratings on outstanding secured debt at June 30,
2002 are A-/A1. VUHI's commercial paper has a credit rating of A-2/P-1.
Cash Flow From Operations
The Company's primary source of liquidity to fund working capital requirements
has been cash generated from operations, which totaled approximately $269.8
million and $105.7 million for the six months ended June 30, 2002 and 2001,
respectively.
Cash flow from operations increased during the six months ended June 30, 2002
compared to 2001 by $164.1 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 June 30, 2002, the Company had $330.0 million of short-term borrowing
capacity, of which $213.8 million was available.
During the six months ended June 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
during the quarter and have been reclassified as long-term debt.
Ratings triggers on VUHI's commercial paper facility existing at December 31,
2001 were removed as the facility was renewed during 2002.
Financing Cash Flow
Cash flow required for financing activities of $200.3 million for the six months
ended June 30, 2002 includes $164.3 million of reductions in net borrowings and
$35.8 million in common stock dividends. In the prior year, $129.4 million of
additional capital was contributed by Vectren and used to repay short-term
borrowings used to purchase the Ohio operations.
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
Cash required for investing activities of $68.1 million for the six months ended
June 30, 2002 includes $69.7 million of requirements for capital expenditures.
Investing activities for the six months ended June 30, 2001 were $38.4 million.
The increase is attributable to capital expenditures for NOx compliance and a
new 80 megawatt peaker unit.
Planned Capital Expenditures
New construction, normal system maintenance and improvements, and information
technology investments needed to provide service to a growing customer base will
continue to require substantial expenditures. Capital expenditure for the
remainder of 2002 is estimated at $83.9 million.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements 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 and other marketing
activities that may expose it to commodity price risk associated with
fluctuating electric power prices. The Company's wholesale power marketing
activities manage the utilization of its available electric generating capacity.
These operations enter into forward and option contracts that commit the Company
to purchase and sell electric power in the future.
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.
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 better utilize and
optimize the return on these key assets. The contracts entered into are
primarily "buy-sell" transactions, short-term in nature, and 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 June 30, 2002, contracts had a net asset value of $0.1
million compared to a net asset value of $3.2 million at December 31, 2001. The
Company has determined these energy marketing contracts are derivatives within
the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities."
Power marketing contracts at June 30, 2002 totaled $9.7 million of prepayments
and other current assets and $9.6 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. The change in the net value of these contracts
to $0.1 million at June 30, 2002 from $3.2 million at December 31, 2001 resulted
in an unrealized loss of $0.1 million and $3.1 million, respectively, for the
three and six months ended June 30, 2002. For the three and six months ended
June 30, 2001, the Company's power marketing operations resulted in unrealized
losses of $7.9 million and $2.4 million, respectively. Including these
unrealized changes in fair value, overall margin (revenue net of purchased
power) from power marketing operations for the three and six months ended June
30, 2002 was $2.4 million and $3.4 million, respectively, and for the three and
six months ended June 30, 2001 was ($4.6) million and $6.8 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 six months ended
June 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 $0.1 million and $1.5 million, respectively. For the three and six
months ended June 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 $1.4 million, respectively.
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 Company's 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.
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 6 regarding ProLiance Energy, LLC.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None
(b) Reports On Form 8-K During The Last Calendar Quarter
On April 25, 2002, the Company filed a Current Report on Form 8-K with respect
to the release of financial information to the investment community regarding
Vectren's results of operations, financial position and cash flows for the three
and twelve month periods ended March 31, 2002. The financial information was
released to the public through this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - First 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 April 25, 2002, the Company filed a current report on From 8-K with respect
to the filing of an agreement with the Indiana Utility Regulatory Commission
setting forth the basic framework for an anticipated settlement of numerous
pending issues related to ProLiance Energy, LLC
Item 5. Other Events
Item 7. Exhibits
99-1 Press Release - Consumer Groups and Utilities Announce
Proposed Agreement on Gas Supply Services from ProLiance
On May 20, 2002, Vectren Corporation filed an amendment to current report on
Form 8-K, originally filed on March 26, 2002, with respect to its decision to
dismiss Arthur Andersen LLP as the independent auditors of Vectren Corporation
effective May 17, 2002. Deloitte & Touche LLP has been selected as the
independent auditor for the company effective May 17, 2002.
Item 4. Changes in Registrant's Certifying Accountant.
Item 7. Exhibits
16 - Letter from Arthur Andersen LLP to the Securities and
Exchange Commission, dated May 20, 2002.
99 - Press release regarding selection of Deloitte & Touche LLP
dated May 20, 2002
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 UTILITY HOLDINGS, INC.
------------------------------
Registrant
August 14, 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
18 U.S.C. SECTION 1350,
AS ADOPTED 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
Utility Holdings, Inc..
Signed this 14th day of August, 2002.
/s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook
- ---------------------------------------- -------------------------------------
(Signature of Authorized Officer) (Signature of Authorized Officer)
Jerome A. Benkert, Jr. Niel C. Ellerbrook
- ---------------------------------------- -------------------------------------
(Typed Name) (Typed Name)
Executive Vice President and
Chief Financial Officer Chairman and Chief Executive Officer
- ---------------------------------------- -------------------------------------
(Title) (Title)