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 1-16739
VECTREN UTILITY HOLDINGS, INC.
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(Exact name of registrant as specified in its charter)
INDIANA 35-2104850
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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 10 November 1, 2002
- ------------------------------- ---------------------- ------------------
Class Number of shares Date
As of November 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
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...5-13
Management's Discussion and Analysis
of Results of Operations and Financial Condition................14-24
Qualitative and Quantitative Disclosures About Market Risk.......25-26
Controls and Procedures.............................................27
Part II. Other Information
Legal Proceedings...................................................28
Exhibits and Reports on Form 8-K....................................28
Signatures..........................................................29
Certifications...................................................30-32
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
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)
September 30, December 31,
2002 2001
--------- ---------
ASSETS
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
-------- --------
Current Assets
Cash & cash equivalents 12.7 7.2
Accounts receivable-less reserves of $7.0 &
$5.6, respectively 78.3 125.3
Receivables from other Vectren companies 15.5 58.2
Accrued unbilled revenues 30.9 78.3
Inventories 53.6 55.3
Recoverable fuel & natural gas costs 45.3 76.5
Prepayments & other current assets 120.7 95.8
-------- --------
Total current assets 357.0 496.6
-------- --------
Investments in unconsolidated affiliates 3.3 4.0
Other investments 16.4 12.2
Non-utility property-net 5.7 6.3
Goodwill-net 199.3 198.6
Regulatory assets 80.0 61.4
Other assets 20.5 17.3
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TOTAL ASSETS $ 2,301.9 $ 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)
September 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 333.9 329.0
Accumulated other comprehensive income (1.9) (1.7)
-------- --------
Total common shareholder's equity 717.7 713.0
-------- --------
Cumulative Redeemable Preferred Stock of Subsidiary 0.3 0.5
Long-term debt- net of current maturities and debt
subject to tender 890.2 900.9
-------- --------
Total capitalization 1,608.2 1,614.4
-------- --------
Commitments & Contingencies (Notes 6-8)
Current Liabilities
Accounts payable 75.2 79.0
Accounts payable to affiliated companies 32.4 36.5
Payables to other Vectren companies 19.4 11.5
Accrued liabilities 91.6 97.5
Short-term borrowings 171.7 274.2
Long-term debt subject to tender - 11.5
Current maturities of long-term debt 17.2 1.3
-------- --------
Total current liabilities 407.5 511.5
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Deferred Income Taxes & Other Liabilities
Deferred income taxes 191.1 171.8
Deferred credits & other liabilities 95.1 93.7
-------- --------
Total deferred income taxes & other liabilities 286.2 265.5
-------- --------
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 2,301.9 $ 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 Nine Months
Ended September 30, Ended September 30,
------------------ ----------------------
2002 2001 2002 2001
-------- -------- --------- ----------
OPERATING REVENUES
Gas revenues $ 88.1 $ 96.0 $ 585.0 $ 774.3
Electric revenues 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 sold 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 costs - 1.4 - 2.1
Restructuring costs - 1.2 - 12.0
Depreciation & amortization 24.2 24.6 71.7 74.1
Income taxes 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
Equity in earnings of unconsolidated affiliates (0.4) - (1.4) -
Other income - net 0.6 1.4 10.7 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) $ 8.9 $ (0.5) $ 58.6 $ 22.3
======= ======= ========= =========
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)
Nine Months Ended
September 30,
------------------
2002 2001
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 58.6 $ 22.3
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 71.7 74.1
Equity in losses of unconsolidated affiliates 1.4 -
Deferred income taxes & investment tax credits 1.5 (3.1)
Net unrealized loss (gain) on derivative instruments,
including cumulative effect of change in
accounting principle 3.0 (3.0)
Other non-cash charges- net 3.9 13.2
Changes in assets and liabilities:
Accounts receivable, including to Vectren
companies & accrued unbilled revenues 128.9 198.2
Inventories 1.7 (5.3)
Recoverable fuel & natural gas costs 31.2 17.1
Prepayments & other current assets (25.1) (28.9)
Regulatory assets - (0.6)
Accounts payable, including to Vectren
companies & affiliated companies 7.4 (136.7)
Accrued liabilities (7.2) (37.9)
Other noncurrent assets & liabilities (6.1) 1.7
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Total adjustments 212.3 88.8
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Net cash flows from operating activities 270.9 111.1
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CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES
Proceeds from additional capital contribution - 129.4
Requirements for:
Dividends on common stock (53.7) (46.7)
Retirement of long-term debt (6.4) (7.3)
Retirement of preferred stock of subsidiary (0.2) (17.7)
Dividends on preferred stock of subsidiary - (0.7)
Net change in short-term borrowings (102.5) (80.2)
----- ------
Net cash flows (required for) financing activities (162.8) (23.2)
----- ------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from investments 2.6 2.1
Requirements for:
Capital expenditures (99.3) (85.9)
Other investments (5.5) (3.9)
Unconsolidated affiliates (0.4) -
----- -----
Net cash flows (required for) investing activities (102.6) (87.7)
----- -----
Net increase in cash & cash equivalents 5.5 0.2
Cash & cash equivalents at beginning of period 7.2 2.2
----- -----
Cash & cash equivalents at end of period $ 12.7 $ 2.4
===== =====
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 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 "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 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. 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 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 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) $ 8.9 $ (0.5) $ 58.6 $ 22.3
Minimum pension liability adjustment
and other- net of tax (0.2) (3.0) (0.2) (4.0)
- -------------------------------------------------------------------------------------------
Total comprehensive income (loss) $ 8.7 $ (3.5) $ 58.4 $ 18.3
===========================================================================================
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 September 30, 2002 and 2001, amounts billed by other wholly owned
subsidiaries of Vectren to the Company were $32.9 million and $16.2 million,
respectively. For the nine months ended September 30, 2002 and 2001, amounts
billed by other wholly owned subsidiaries of Vectren to the Company were $99.7
million and $88.9 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 September 30, 2002
and 2001 were $17.3 million and $7.3 million, respectively. Amounts paid for
such purchases for the nine months ended September 30, 2002 and 2001 were $45.6
million and $28.2 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 $168.5
million is outstanding at September 30, 2002 and VUHI's $350.0 million unsecured
senior notes outstanding at September 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 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. As result of the settlement,
Indiana Gas will refund amounts to customers. The Company expects refunds to be
made in December 2002. A subsidiary of Vectren's nonregulated operations has
indemnified Indiana Gas for the amount of the refund as well as any other
amounts incurred as a result of the settlement. Accordingly, the refund has no
effect on operating margin or net income.
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.
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.
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 transactions 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
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 electric transmission and distribution services, which provides
electricity to primarily southwestern Indiana, and SIGECO's power generating and
power marketing operations. 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
------ ------ -------- --------
Total operating revenues $ 278.1 $ 200.3 $ 1,060.7 $ 1,061.8
====== ====== ======== ========
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
------ ------ -------- --------
Net income (loss) $ 8.9 $ (0.5) $ 58.6 $ 22.3
====== ====== ======== ========
September 30, December 31,
In millions 2002 2001
------------ -----------
Identifiable Assets
Gas Utility Services $1,459.3 $1,580.2
Electric Utility Services 842.6 811.2
------- -------
Total identifiable assets $2,301.9 $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
---------------------
Three Months Nine Months
Ended September 30, Ended September 30,
--------------------- --------------------
In millions 2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------
Net income (loss), as reported $ 8.9 $ (0.5) $ 58.6 $ 22.3
Merger, integration, & other costs-net of tax - 0.7 - 7.4
Restructuring costs-net of tax 2.5 6.5
Cumulative effect of change in accounting
principle - net of tax - - - (3.9)
- ----------------------------------------------------------------------------------------------------------
Net income before nonrecurring items $ 8.9 $ 2.7 $ 58.6 $ 32.3
==========================================================================================================
Net Income
- ----------
For the nine months ended September 30, 2002, net income was $58.6 million
compared to $22.3 million 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 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, net income was $8.9 million
compared to a net loss of $0.5 million for the same period in 2001. Earnings
increased due to due to increased margins, partly reflecting favorable cooling
weather. The completion of merger and restructuring activities and related costs
in 2001 also contributed.
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 "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 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 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.
Significant Fluctuations
- ------------------------
Utility Margin
- --------------
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.
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 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. As result of the settlement,
Indiana Gas will refund amounts to customers. The Company expects refunds to be
made in December 2002. A subsidiary of Vectren's nonregulated operations has
indemnified Indiana Gas for the amount of the refund as well as any other
amounts incurred as a result of the settlement. Accordingly, the refund has no
effect on operating margin or net income.
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.
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
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
September, 2002 are A-/A2 as rated by Standard and Poor's and Moody's,
respectively. SIGECO's credit ratings on outstanding secured debt at September
30, 2002 are A-/A1. VUHI's commercial paper has a credit rating of A-2/P-1. 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; and the regulatory treatment of the significant NOx environmental
expenditures. The Company continues to work with Moody's to address these items
including the favorable NOx settlement and other items involving Vectren and
other Vectren subsidiaries.
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 $270.9
million and $111.1 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 $159.8 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 $330.0 million of short-term borrowing
capacity, of which $158.3 million was available.
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.
Ratings triggers on VUHI's commercial paper back up 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 $162.8 million for the nine
months ended September 30, 2002 includes $108.9 million of reductions in net
borrowings and $53.7 million in common stock dividends paid to Vectren. 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 $102.6 million for the nine months
ended September 30, 2002 includes $99.3 million of requirements for capital
expenditures. Investing activities for the nine months ended September 30, 2001
were $87.7 million. The increase is attributable to capital expenditures for NOx
compliance.
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 expenditures for the
remainder of 2002 are estimated at $42.8 million. Estimated capital expenditures
for 2003 are estimated at $204.8 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 operations that may
expose it to commodity price risk associated with fluctuating electric power
prices. The Company's wholesale power marketing operations 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 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.
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.
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 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 July 23, 2002, The Company 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, The Company 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
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
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 Utility
Holdings, Inc.;
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 Utility
Holdings, Inc.;
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
Utility Holdings, Inc..
Signed this 13th day of November, 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)