UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For quarterly period ended June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-15467
VECTREN CORPORATION
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(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
20 N.W. Fourth Street, Evansville, Indiana 47708
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(Address of principal executive offices and Zip Code)
(812) 491-4000
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock - Without par value 67,780,679 August 1, 2002
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Class Number of shares Date
Table of Contents
Item Page
Number Number
PART I. FINANCIAL INFORMATION
1 Financial Statements (Unaudited)
Vectren Corporation and Subsidiary Companies
Consolidated Condensed Balance Sheets 1-2
Consolidated Condensed Statements of Income 3
Consolidated Condensed Statements of Cash Flows 4
Notes to Unaudited Consolidated Condensed Financial Statements 5-14
2 Management's Discussion and Analysis of Results of Operations 15-32
and Financial Condition
3 Quantitative and Qualitative Disclosures About Market Risk 33-34
PART II. OTHER INFORMATION
1 Legal Proceedings 35
4 Submission of Matters to a Vote of Security Holders 35
6 Exhibits and Reports on Form 8-K 35-36
Signatures 37
Certification Pursuant To 18 U.S.C. Section 1350, 38
As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley Act Of 2002
Definitions
As discussed in this Form 10-Q, the abbreviations
AFUDC means allowance for funds used during construction,
APB means Accounting Principles Board
EITF means Emerging Issues Task Force,
FASB means Financial Accounting Standards Board,
IDEM means Indiana Department of Environmental Management,
IURC means Indiana Utility Regulatory Commission,
MMDth means millions of dekatherms,
MMBTU means millions of British thermal units,
PUCO means Public Utilities Commission of Ohio,
USEPA means United States Environmental Protection Agency, and
throughput means combined gas sales and gas transportation volumes.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
June 30, December 31,
2002 2001
- --------------------------------------------------- --------- -----------
ASSETS
Current Assets
Cash & cash equivalents $ 21.2 $ 27.2
Accounts receivable-less reserves of $4.1 &
$5.9, respectively 111.6 213.8
Accrued unbilled revenues 28.5 78.4
Inventories 44.9 71.4
Recoverable fuel & natural gas costs 50.9 76.5
Prepayments & other current assets 74.8 103.4
-------- --------
Total current assets 331.9 570.7
-------- --------
Utility Plant
Original cost 2,966.4 2,903.2
Less: accumulated depreciation & amortization 1,346.6 1,308.2
-------- --------
Net utility plant 1,619.8 1,595.0
-------- --------
Investments in unconsolidated affiliates 157.4 127.7
Other investments 115.4 100.3
Non-utility property-net 184.5 181.7
Goodwill-net 199.3 199.3
Regulatory assets 80.7 61.4
Other assets 31.3 20.7
-------- --------
TOTAL ASSETS $ 2,720.3 $ 2,856.8
======== ========
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
June 30, December 31,
2002 2001
- ---------------------------------------------- --------- ------------
LIABILITIES & SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 75.2 $ 144.4
Accounts payable to affiliated companies 33.7 37.2
Accrued liabilities 116.2 101.4
Short-term borrowings 260.8 381.7
Long-term debt subject to tender - 11.5
Current maturities of long-term debt 17.3 1.3
-------- --------
Total current liabilities 503.2 677.5
-------- --------
Deferred Income Taxes & Other Liabilities
Deferred income taxes 224.6 206.7
Deferred credits & other liabilities 114.0 108.1
-------- --------
Total deferred income taxes & other liabilities 338.6 314.8
-------- --------
Commitments & Contingencies (Notes 6 - 8)
Minority Interest in Subsidiary 1.1 1.4
Capitalization
Long-term debt-net of current maturities and
debt subject to tender 1,003.4 1,014.0
Cumulative redeemable preferred stock of
subsidiary 0.3 0.5
Common shareholders' equity
Common stock (no par value) - issued &
outstanding 67.8 and 67.7, respectively 347.8 346.1
Retained earnings 522.0 498.3
Accumulated other comprehensive income 3.9 4.2
-------- --------
Total common shareholders' equity 873.7 848.6
-------- --------
Total capitalization 1,877.4 1,863.1
-------- --------
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,720.3 $ 2,856.8
======== ========
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited - In millions, except per share data)
Three Months Six Months
Ended June 30, Ended June 30,
----------------- ------------------
2002 2001 2002 2001
- --------------------------------------------- ------- ------- -------- --------
OPERATING REVENUES
Gas utility $ 139.8 $ 154.6 $ 496.9 $ 678.3
Electric utility 158.9 95.0 285.7 183.2
Energy services & other 88.2 183.5 239.5 455.5
------- ------- ------- -------
Total operating revenues 386.9 433.1 1,022.1 1,317.0
------- ------- ------- -------
OPERATING EXPENSES
Cost of gas sold 81.9 94.8 311.9 498.9
Fuel for electric generation 19.0 17.8 36.8 35.8
Purchased electric energy 87.0 33.6 146.8 46.8
Cost of energy services & other 79.1 177.0 218.5 438.8
Other operating 57.4 58.9 114.0 120.5
Merger & integration costs - - - 0.8
Restructuring costs - 11.8 - 11.8
Depreciation & amortization 28.7 31.9 57.8 63.3
Taxes other than income taxes 10.2 11.1 28.5 30.6
------- ------- ------- -------
Total operating expenses 363.3 436.9 914.3 1,247.3
------- ------- ------- -------
OPERATING INCOME (LOSS) 23.6 (3.8) 107.8 69.7
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 3.8 4.2 6.1 10.1
Other - net 7.7 5.0 9.1 7.9
------- ------- ------- -------
Total other income 11.5 9.2 15.2 18.0
------- ------- ------- -------
Interest expense 19.3 21.0 39.1 43.8
------- ------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES 15.8 (15.6) 83.9 43.9
------- ------- ------- -------
Income taxes 1.5 (5.7) 24.2 13.1
Minority interest in subsidiary - (0.2) (0.2) (0.2)
Preferred dividend requirement of subsidiary - 0.3 - 0.5
------- ------- ------- -------
INCOME (LOSS) BEFORE EXTRAORDINARY
LOSS & CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 14.3 (10.0) 59.9 30.5
------- ------- ------- -------
Extraordinary loss - net of tax - (7.7) - (7.7)
Cumulative effect of change in accounting
principle - net of tax - - - 3.9
------- ------- ------- -------
NET INCOME (LOSS) $ 14.3 $ (17.7) $ 59.9 $ 26.7
======= ======= ======= =======
AVERAGE COMMON SHARES OUTSTANDING 67.6 67.7 67.5 66.2
DILUTED COMMON SHARES OUTSTANDING 67.9 67.7 67.8 66.3
EARNINGS PER SHARE OF COMMON STOCK:
BASIC
INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.21 $ (0.15) $ 0.89 $ 0.46
Extraordinary loss - net of tax - (0.11) - (0.12)
Cumulative effect of change in accounting
principle - net of tax - - - 0.06
BASIC EARNINGS (LOSS) PER SHARE ------- ------- ------- -------
OF COMMON STOCK $ 0.21 $ (0.26) $ 0.89 $ 0.40
======= ======= ======= =======
DILUTED
INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.21 $ (0.15) $ 0.88 $ 0.46
Extraordinary loss - net of tax - (0.11) - (0.12)
Cumulative effect of change in accounting principle
- net of tax - - - 0.06
DILUTED EARNINGS (LOSS) PER SHARE ------- ------- ------- -------
OF COMMON STOCK $ 0.21 $ (0.26) $ 0.88 $ 0.40
======= ======= ======= =======
DIVIDENDS DECLARED PER SHARE
OF COMMON STOCK $ 0.27 $ 0.26 $ 0.53 $ 0.51
======= ======= ======= =======
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited - In millions)
Six Months
Ended June 30,
-----------------
2002 2001
- ------------------------------------------------------------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 59.9 $ 26.7
Adjustments to reconcile net income to cash from
operating activities:
Depreciation & amortization 57.8 63.3
Deferred income taxes & investment tax credits 1.3 (1.5)
Equity in earnings of unconsolidated affiliates (6.1) (10.1)
Restructuring costs - 11.8
Extraordinary loss - net of tax - 7.7
Net unrealized loss (gain) on derivative instruments,
including cumulative effect of change in
accounting principle 3.1 (3.9)
Other non-cash charges - net 3.1 5.9
Changes in assets and liabilities:
Accounts receivable & accrued unbilled revenues 103.4 201.0
Inventories 18.8 31.8
Recoverable fuel & natural gas costs 25.6 (0.6)
Prepayments & other current assets 32.2 10.9
Regulatory assets - (1.2)
Accounts payable, including to affiliated companies (36.9) (160.8)
Accrued liabilities 6.2 (26.1)
Other noncurrent assets & liabilities (13.1) 0.7
------ ------
Total adjustments 195.4 128.9
------ ------
Net cash flows from operating activities 255.3 155.6
------ ------
CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES
Proceeds from:
Issuance of common stock - net of issuance costs - 129.4
Requirements for:
Dividends on common stock (35.8) (34.4)
Retirement of long-term debt (6.3) (7.2)
Redemption of preferred stock of subsidiary (0.2) (0.2)
Dividends on preferred stock of subsidiary - (0.2)
Net change in short-term borrowings (116.3) (147.4)
Proceeds from exercise of stock options & other 1.4 0.6
------ ------
Net cash flows (required for) financing activities (157.2) (59.4)
------ ------
CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES
Proceeds from:
Notes receivable & other investments 3.7 -
Unconsolidated affiliate distributions 2.7 5.9
Requirements for:
Capital expenditures (94.4) (87.3)
Notes receivable & other investments (8.1) (5.6)
Unconsolidated affiliate investments (8.0) (5.6)
------ ------
Net cash flows (required for) investing activities (104.1) (92.6)
------ ------
Net (decrease) increase in cash & cash equivalents (6.0) 3.6
Cash & cash equivalents at beginning of period 27.2 15.2
------ ------
Cash & cash equivalents at end of period $ 21.2 $ 18.8
====== ======
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Nature of Operations
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999 solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with Accounting Principles
Board (APB) Opinion No. 16 "Business Combinations."
Vectren is a public utility holding company, whose wholly owned subsidiary,
Vectren Utility Holdings, Inc. (VUHI), is the intermediate holding company for
the Company's three operating public utilities: Indiana Gas Company, Inc.
(Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern
Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of
SIGCORP, and the Ohio operations. Indiana Gas provides natural gas distribution
and transportation services to a diversified customer base in 311 communities in
49 of Indiana's 92 counties. SIGECO provides electric generation, transmission,
and distribution services to Evansville, Indiana, and 74 other communities in 8
counties in southwestern Indiana and participates in the wholesale power market.
SIGECO also provides natural gas distribution and transportation services to
Evansville, Indiana, and 64 communities in 10 counties in southwestern Indiana.
The Ohio operations, owned as a tenancy in common by Vectren Energy Delivery of
Ohio, Inc., a wholly owned subsidiary, (53 % ownership) and Indiana Gas (47 %
ownership), provide natural gas distribution and transportation services to
Dayton, Ohio, and 87 other communities in 17 counties in west central Ohio. The
Ohio operations were acquired from the Dayton Power & Light Company on October
31, 2000. Both Vectren and VUHI are exempt from registration pursuant to Section
3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates Internal Revenue Service (IRS) Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels.
Utility Infrastructure Services provides underground construction and repair,
facilities locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the nonregulated group has investments in other businesses that
invest in energy-related opportunities and provide utility services, municipal
broadband consulting, retail services, and real estate and leveraged lease
investments.
2. Basis of Presentation
The interim consolidated condensed financial statements included in this report
have been prepared by the Company, without audit, as provided in the rules and
regulations of the Securities and Exchange Commission. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with accounting principles generally accepted in the United States
have been omitted as provided in such rules and regulations. The Company
believes that the information in this report reflects all adjustments necessary
to fairly state the results of the interim periods reported. These consolidated
condensed financial statements and related notes should be read in conjunction
with the Company's audited annual consolidated financial statements for the year
ended December 31, 2001, filed on Form 10-K. Because of the seasonal nature of
the Company's utility operations, the results shown on a quarterly basis are not
necessarily indicative of annual results.
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the statements
and the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from those estimates.
Certain reclassifications have been made to prior period financial statements to
conform with the current year classification. These reclassifications have no
impact on previously reported net income.
3. Impact of Recently Issued Accounting Guidance
EITF 02-03
In June 2002, the EITF reached a final consensus in EITF Issue 02-03 "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that states mark-to-market gains and losses on energy trading contracts
(whether realized or unrealized and whether financially or physically settled)
should be shown net in the income statement and that expanded disclosure of
energy trading activities is required. This consensus is effective for periods
ending after July 15, 2002, with reclassification of prior period amounts
required.
The Company currently accounts for all its power and gas marketing contracts at
gross in the Consolidated Condensed Statements of Income. The Company has
reviewed all of its current power marketing contracts and all contracts closed
in prior periods and identified no energy trading contracts subject to EITF
02-03. See Note 9 for additional information on the Company's power marketing
operations.
SFAS 142
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS 142). The Company adopted the provisions of SFAS 142, as required
on January 1, 2002. SFAS 142 changed the accounting for goodwill from an
amortization approach to an impairment-only approach. Thus, amortization of
goodwill that is not included as an allowable cost for rate-making purposes
ceased upon adoption of this statement. This includes goodwill recorded in past
business combinations, such as the Company's acquisition of the Ohio operations.
Goodwill is to be tested for impairment at a reporting unit level at least
annually.
SFAS 142 also required the initial impairment review of all goodwill within six
months of the adoption date. The impairment review consisted of a comparison of
the fair value of a reporting unit to its carrying amount. If the fair value of
a reporting unit is less than its carrying amount, an impairment loss would be
recognized. Results of the initial impairment review were to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations. SFAS 142 also changed certain aspects of accounting for other
intangible assets; however, the Company does not have any other significant
intangible assets.
As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations, which approximates $5.0 million per year, ceased on January
1, 2002. Initial impairment reviews to be performed within six months of
adoption of SFAS 142 were completed and resulted in no impairment.
SFAS 144
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations are no longer
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
The adoption of SFAS 144 on January 1, 2002 did not materially impact
operations.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
4. Comprehensive Income
Comprehensive income consists of the following:
Three Months Six Months
Ended June 30, Ended June 30,
------------------ ------------------
In millions 2002 2001 2002 2001
- ------------------------------------------ ------- -------- ------- -------
Net income (loss) $ 14.3 $ (17.7) $ 59.9 $ 26.7
Comprehensive income (loss) of
unconsolidated affiliates - net of tax 2.1 (4.4) (0.2) (11.1)
Minimum pension liability adjustment
and other- net of tax - (0.1) - (1.0)
------ ------ ------ ------
Total comprehensive income (loss) $ 16.4 $ (22.2) $ 59.7 $ 14.6
====== ====== ====== ======
Comprehensive income arising from unconsolidated affiliates is the Company's
portion of ProLiance Energy LLC's other comprehensive income related to its use
of cash flow hedges and the Company's portion of Haddington Energy Partners, LP
other comprehensive income related to unrealized gains and losses of
available-for-sale securities.
5. Earnings Per Share
Basic earnings per share is computed by dividing net income available to common
shareholders by the weighted-average number of common shares outstanding for the
period. Diluted earnings per share assumes the conversion of stock options into
common shares and the lifting of restrictions on issued restricted shares using
the treasury stock method to the extent the effect would be dilutive. The
following table illustrates the basic and dilutive earnings per share
calculations for the three and six months ended June 30, 2002 and 2001:
Three Months Ended June 30,
In millions, except --------------------------------------------------------
per share amounts 2002 2001
--------------------------- --------------------------
Per Per
Share Share
Income Shares Amount Loss Shares Amount
------ ------ ------ ------- ------ -------
Basic EPS $ 14.3 67.6 $ 0.21 $ (17.7) 67.7 $ (0.26)
Effect of dilutive
stock equivalents 0.3 -
------ ------ ------ ------- ------ -------
Diluted EPS $ 14.3 67.9 $ 0.21 $ (17.7) 67.7 $ (0.26)
====== ====== ====== ======= ====== =======
Six Months Ended June 30,
------------------------------------------------------
2002 2001
-------------------------- -------------------------
Per Per
Share Share
Income Shares Amount Income Shares Amount
------ ------ ------ ------ ------ ------
Basic EPS $ 59.9 67.5 $ 0.89 $ 26.7 66.2 $ 0.40
Effect of dilutive
stock equivalents 0.3 0.1
------ ------ ------ ------ ------ ------
Diluted EPS $ 59.9 67.8 $ 0.88 $ 26.7 66.3 $ 0.40
====== ====== ====== ====== ====== ======
For the three months ended June 30, 2002 and 2001, options to purchase an
additional 4,200 and 1,514,060 common shares of the Company's common stock were
outstanding, but were not included in the computation of diluted earnings per
share because their effect would be antidilutive. Exercise prices for options
excluded from the computation equaled $25.59 in 2002 and ranged from $13.82 to
$24.05 in 2001.
For the six months ended June 30, 2002 and 2001, options to purchase an
additional 22,274 and 834,304 common shares of the Company's common stock were
outstanding, but were not included in the computation of diluted earnings per
share because their effect would be antidilutive. Exercise prices for options
excluded from the computation ranged from $24.90 to $25.59 in 2002 and ranged
from $22.54 to $24.05 in 2001.
6. Commitments & Contingencies
Guarantees
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees include debt guarantees and performance guarantees, including the
debt of and performance of energy efficiency products installed by affiliated
companies. The Company estimates these totaled approximately $90 million at June
30, 2002. The Company's most significant guarantee totaling $58.2 million at
June 30, 2002 represents two-thirds of Energy Systems Group, LLC's (ESG) surety
bonds, performance and energy savings guarantees. ESG is a two-thirds owned
consolidated subsidiary. The guarantees relate to amounts due to various
insurance companies for surety bonds should ESG default on obligations to
complete construction, pay vendors or subcontractors, and achieve energy
guarantees. Through June 30, 2002, the Company has not been called upon to
satisfy any obligations pursuant to the guarantees.
Legal Proceedings
The Company is party to various legal and regulatory proceedings arising in the
normal course of business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position or results of operations. See Note 7
regarding ProLiance Energy, LLC and Note 8 regarding environmental matters.
7. Unconsolidated Affiliates
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), began providing
natural gas and related services to Indiana Gas, Citizens Gas, and others in
April 1996. ProLiance also provides services to the Ohio operations and began
providing service to SIGECO in 2002. ProLiance's primary business is optimizing
the gas portfolios of utilities and providing services to large end use
customers.
Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC
In February 2002, Vectren announced its intention to integrate the operations of
its wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance.
SES provides natural gas and related services to SIGECO and others. Effective
June 1, 2002, the integration was completed. In exchange for the contribution of
SES' net assets totaling $19.4 (including cash of $2.2 million), Vectren's
allocable share of ProLiance's profits and losses increased from 52.5% to 61%,
consistent with Vectren's new ownership percentage. However, governance,
including voting rights, remain at 50% for each member. As governance of
ProLiance remains equal between the members, Vectren continues to account for
its investment in ProLiance using the equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. The transfer of net assets was
accounted for at book value consistent with joint venture accounting and did not
result in any gain or loss. Additionally, the non-cash component of the transfer
totaling $17.2 million is excluded from the Consolidated Condensed Statement of
Cash Flows.
Regulatory Matters
The sale of gas and provision of other services to Indiana Gas and SIGECO by
ProLiance is subject to regulatory review through the quarterly gas cost
adjustment (GCA) process administered by the IURC. The sale of gas and provision
of other services to the Ohio operations by ProLiance is subject to regulatory
review through the quarterly gas cost recovery (GCR) process administered by the
PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility. The
IURC's decision reflected the significant gas cost savings to customers obtained
through ProLiance's services and suggested that all material provisions of the
agreements between ProLiance and the utilities are reasonable. Nevertheless,
with respect to the pricing of gas commodity purchased from ProLiance, the price
paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in the pending, consolidated GCA proceeding involving Indiana
Gas and Citizens Gas.
In 2001, the IURC commenced processing the GCA proceeding regarding the three
pricing issues. The IURC indicated that it would consider the prospective
relationship of ProLiance with the utilities in this proceeding. On April 23,
2002, Indiana Gas and Citizens Gas, together with the Office of Utility Consumer
Counselor and other consumer parties, entered into and filed with the IURC an
agreement in principle setting forth the terms for resolution of all pending
regulatory issues related to ProLiance. The parties submitted for IURC approval
a final settlement on June 4, 2002. On July 23, 2002, the IURC approved the
settlement filed by the parties. Any appeal of the IURC's approval order must be
filed by August 23, 2002. The GCA proceeding has been concluded and new supply
agreements between Indiana Gas, SIGECO, Citizens Gas, and ProLiance have been
approved and extended through March 31, 2007. At June 30, 2002 and December 31,
2001, the Company has reserved approximately $4.0 million and $3.2 million,
respectively, of ProLiance's after tax earnings for exposure from this GCA
proceeding. Any additional effect on earnings as a result of the final
settlement for past services provided to Indiana Gas by ProLiance is not
material.
Pre-tax income of $5.4 million and $4.0 million was recognized as ProLiance's
contribution to earnings for the three months ended June 30, 2002 and 2001,
respectively. Pre-tax income of $10.8 million and $9.6 million was recognized as
ProLiance's contribution to earnings for the six months ended June 30, 2002 and
2001, respectively. Earnings recognized from ProLiance are included in equity in
earnings of unconsolidated affiliates.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the
three months ended June 30, 2002 and 2001 totaled $108.7 million and $146.0
million, respectively; and for the six months ended June 30, 2002 and 2001
totaled $236.5 million and $414.4 million, respectively. Amounts owed to
ProLiance at June 30, 2002 and December 31, 2001 for those purchases were $32.5
million and $36.1 million, respectively, and are included in accounts payable to
affiliated companies. Amounts charged by ProLiance for gas supply services are
set forth by supply agreements with each utility.
Utilicom Networks, LLC
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including analog and digital
cable television, high-speed Internet, and advanced local and long distance
phone services. The Company has a 14% interest in Class A units of Utilicom,
which is accounted for using the equity method of accounting. The Company also
has a minority interest in SIGECOM Holdings, Inc. (Holdings), which was formed
by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). The Company accounts
for its investment in Holdings on the cost method. SIGECOM provides broadband
services to the greater Evansville, Indiana, area. Utilicom also plans to
provide broadband services to the greater Indianapolis, Indiana, and Dayton,
Ohio, markets.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is due to the
continued difficult environment within the telecommunication capital markets,
which has prevented Utilicom from obtaining debt financing on terms it considers
acceptable. While the existing investors are still committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded. This delay
necessitated and resulted in the extension of the franchising agreements into
the third quarter of 2002.
8. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the United States Environmental
Protection Agency (USEPA) finds a state's SIP inadequate to achieve the NAAQS,
the USEPA can call upon the state to revise its SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1998 and 1999.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002.
The Company has recently filed another proceeding with the IURC to receive
approval of additional capital costs and to obtain approval for recovery of
future operating costs, including depreciation, related to the SCR's through a
rider mechanism. Based on the level of system-wide emissions reductions required
and the control technology utilized to achieve the reductions, the current
estimated construction cost ranges from $240 million to $250 million and is
expected to be expended during the 2001-2006 period. Through June 30, 2002,
$41.0 million has been expended. After the equipment is installed and
operational, related additional annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by: (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits; (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology; and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair and replacement activities
at the Culley Generating Station, as allowed under the Act. Because proper
maintenance does not require permits, application of the best available control
technology, notice to the USEPA, or compliance with new source performance
standards, SIGECO believes that the lawsuit is without merit, and intends to
vigorously defend itself. Since the filing of this lawsuit, the USEPA has
voluntarily dismissed a majority of the claims brought in its original
compliant. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual and
the plant continues to operate while the matter is being decided.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by expert consultants, Indiana Gas has accrued
the estimated costs for further investigation, remediation, groundwater
monitoring and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In June of 2002, the Company received a request from the IDEM concerning
information on any manufactured gas plant sites which the Company has not
enrolled in IDEM's Voluntary Remediation Program, specifically five sites which
were owned and/or operated by SIGECO. Preliminary site investigations conducted
by SIGECO in the mid-1990's confirmed that based upon the conditions known at
the time, the sites posed no risk to human health or the environment.
9. Energy Marketing Activities
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to better utilize and
optimize the return on these key assets. The contracts entered into are
primarily "buy-sell" transactions, short-term in nature, and expose the Company
to limited market risk. During 2002, the Company has increased its activity in
the wholesale market. With the exception of those contracts subject to the
normal purchase and sale exclusion, commodity contracts are accounted for at
market value. As of June 30, 2002, contracts had a net asset value of $0.1
million compared to a net asset value of $3.2 million at December 31, 2001. The
Company has determined these energy marketing contracts are derivatives within
the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities."
Contracts recorded at market value are recorded as current or noncurrent assets
or liabilities in the Consolidated Condensed Balance Sheets depending on their
value and on when the contracts are expected to be settled. Changes in market
value, which is a function of the normal decline in fair value as earnings are
realized and the fluctuation in fair value resulting from price volatility, are
recorded in purchased electric energy in the Consolidated Condensed Statements
of Income. Market value is determined using quoted market prices from
independent sources, or absent quoted market prices, other valuation techniques.
Forward sale contracts, premiums received for written options, and proceeds
received from exercised options are recorded when settled as electric utility
revenues in the Consolidated Condensed Statements of Income. Forward purchase
contracts, premiums paid for purchased options, and proceeds paid for exercising
options are recorded when settled in purchased electric energy in the
Consolidated Condensed Statements of Income. Contracts with counter-parties
subject to master netting arrangements are presented net in the Consolidated
Condensed Balance Sheets.
Power marketing contracts at June 30, 2002 totaled $9.7 million of prepayments
and other current assets and $9.6 million of accrued liabilities, compared to
$5.2 million of prepayments and other current assets and $2.0 million of accrued
liabilities at December 31, 2001. The change in the net value of these contracts
to $0.1 million at June 30, 2002 from $3.2 million at December 31, 2001 resulted
in an unrealized loss of $0.1 million and $3.1 million, respectively, for the
three and six months ended June 30, 2002. For the three and six months ended
June 30, 2001, the Company's power marketing operations resulted in unrealized
losses of $7.9 million and $2.4 million, respectively. Including these
unrealized changes in fair value, overall margin (revenue net of purchased
power) from power marketing operations for the three and six months ended June
30, 2002 was $2.4 million and $3.4 million, respectively, and for the three and
six months ended June 30, 2001 was ($4.6) million and $6.8 million,
respectively.
10. Segment Reporting
The Company had four operating segments during the three and six months ended
June 30, 2002: (1) Gas Utility Services, (2) Electric Utility Services, (3)
Nonregulated Operations, and (4) Corporate and Other. The Gas Utility Services
segment provides natural gas distribution and transportation services in nearly
two-thirds of Indiana and west central Ohio. The Electric Utility Services
segment provides electricity to primarily southwestern Indiana. The Nonregulated
Operations segment is comprised of various subsidiaries and affiliates offering
and investing in energy marketing and services, coal mining, utility
infrastructure services, and broadband communications among other energy-related
opportunities. The Corporate and Other segment provides general and
administrative support and assets, including computer hardware and software, to
the Company's other operating segments. Data for the three and six months ended
June 30, 2001 has been restated to conform to the current year presentation. The
following tables provide information about business segments.
Three Months Six Months
Ended June 30, Ended June 30,
------------------- ----------------------
In millions 2002 2001 2002 2001
-------- -------- ---------- ----------
Operating Revenues
Gas Utility Services $ 139.8 $ 154.6 $ 496.9 $ 678.3
Electric Utility Services 158.9 95.0 285.7 183.2
Nonregulated Operations 104.1 193.4 269.4 477.0
Corporate & Other 5.6 9.0 11.3 17.9
Intersegment Eliminations (21.5) (18.9) (41.2) (39.4)
------ ------- -------- --------
Total operating revenues $ 386.9 $ 433.1 $ 1,022.1 $ 1,317.0
====== ======= ======== ========
Net Income (Loss)
Gas Utility Services $ (3.1) $ (16.1) $ 29.8 $ 2.7
Electric Utility Services 12.2 3.2 19.9 20.1
Nonregulated Operations 4.0 (2.6) 9.0 4.9
Corporate & Other 1.2 (2.2) 1.2 (1.0)
------ ------ -------- --------
Net income (loss) $ 14.3 $ (17.7) $ 59.9 $ 26.7
====== ====== ======== ========
June 30, December 31,
2002 2001
-------- --------
Identifiable Assets
Gas Utility Services $1,404.8 $1,580.2
Electric Utility Services 841.2 811.2
Nonregulated Operations 390.0 466.1
Corporate & Other 143.1 152.4
Intersegment Eliminations (58.8) (153.1)
------- -------
Total identifiable assets $2,720.3 $2,856.8
======= =======
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999 solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations."
Vectren is a public utility holding company, whose wholly owned subsidiary,
Vectren Utility Holdings, Inc. (VUHI), is the intermediate holding company for
the Company's three operating public utilities: Indiana Gas Company, Inc.
(Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern
Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of
SIGCORP, and the Ohio operations. Indiana Gas provides natural gas distribution
and transportation services to a diversified customer base in 311 communities in
49 of Indiana's 92 counties. SIGECO provides electric generation, transmission,
and distribution services to Evansville, Indiana, and 74 other communities in 8
counties in southwestern Indiana and participates in the wholesale power market.
SIGECO also provides natural gas distribution and transportation services to
Evansville, Indiana, and 64 communities in 10 counties in southwestern Indiana.
The Ohio operations, owned as a tenancy in common by Vectren Energy Delivery of
Ohio, Inc., a wholly owned subsidiary, (53 % ownership) and Indiana Gas (47 %
ownership), provide natural gas distribution and transportation services to
Dayton, Ohio, and 87 other communities in 17 counties in west central Ohio. The
Ohio operations were acquired from the Dayton Power & Light Company on October
31, 2000. Both Vectren and VUHI are exempt from registration pursuant to Section
3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates Internal Revenue Service (IRS) Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels.
Utility Infrastructure Services provides underground construction and repair,
facilities locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the nonregulated group has investments in other businesses that
invest in energy-related opportunities and provide utility services, municipal
broadband consulting, retail services, and real estate and leveraged lease
investments.
Consolidated Results of Operations
Three Months Six Months
Ended June 30, Ended June 30,
---------------- ----------------
In millions, except per share amounts 2002 2001 2002 2001
- --------------------------------------------- ------ ------- ------ -------
Net income (loss), as reported $ 14.3 $ (17.7) $ 59.9 $ 26.7
Restructuring costs - net of tax - 7.3 - 7.3
Merger & integration costs - net of tax - 1.7 - 4.0
Extraordinary loss - net of tax - 7.7 - 7.7
Cumulative effect of change in accounting
principle - net of tax - - - (3.9)
------ ------ ------ ------
Net income (loss) before nonrecurring items $ 14.3 $ (1.0) $ 59.9 $ 41.8
====== ====== ====== ======
Attributed to:
Regulated $ 9.1 $ (4.5) $ 49.7 $ 29.6
Nonregulated 4.0 5.5 9.0 13.0
Corporate & other 1.2 (2.0) 1.2 (0.8)
------ ------ ------ ------
Basic earnings (loss) per share, as reported $ 0.21 $ (0.26) $ 0.89 $ 0.40
Restructuring costs - 0.11 - 0.11
Merger & integration costs - 0.03 - 0.06
Extraordinary loss - 0.11 - 0.12
Cumulative effect of change in accounting
principle - - - (0.06)
------ ------ ------ ------
Basic earnings (loss) per share before
nonrecurring items $ 0.21 $ (0.01) $ 0.89 $ 0.63
====== ====== ====== ======
Attributed to:
Regulated $ 0.14 $ (0.07) $ 0.74 $ 0.44
Nonregulated 0.06 0.08 0.13 0.20
Corporate & other 0.01 (0.02) 0.02 (0.01)
Overview
For the three months ended June 30, 2002, net income was $14.3 million, or $0.21
per share, compared to a net loss of $17.7 million, or $0.26 per share in 2001.
For the six months ended June 30, 2002, net income was $59.9 million, or $0.89
per share, compared to net income of $26.7 million, or $0.40 per share in 2001.
The $32.0 million increase for the three month period and the $33.2 million
increase for the six month period results primarily from the nonrecurring
charges related to merger and integration, restructuring, and the extraordinary
loss resulting from leveraged lease dispositions reported in 2001. The increase
for the six-month period is offset by the cumulative effect recorded on adoption
of Statement of Financial Accounting Standard No 133 "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133).
Net income before the impact of these nonrecurring items for the three months
ended June 30, 2002 was also positively affected compared to the prior year by
the accrual of carrying costs on the Company's demand side management programs
consistent with an existing IURC rate order, increased margin from favorable
weather, merger synergies, and increased earnings from the Energy Marketing and
Services Group, a component of Nonregulated operations. However, these increases
were offset somewhat by decreased interest and leveraged lease income due to the
divestiture of notes receivable and leveraged lease investments in 2001. In
addition, a change in Indiana tax laws, enacted in June 2002, negatively
impacted earnings, resulting from the recalculation of deferred tax assets and
liabilities.
Results for the six-month period were also positively affected by a return to
lower gas prices and the related reduction in costs incurred in 2001, but were
negatively impacted by warm weather during the peak 2001-2002 heating season and
decreased nonregulated earnings due to a 2001 gain from the sale of an
investment in a gathering and processing company.
Dividends
Dividends declared for the three and six months ended June 30, 2002 were $0.265
per share and $0.530 per share, respectively, compared to $0.255 per share and
$0.510 per share for the same periods in 2001.
New Accounting Principles
EITF 02-03
In June 2002, the EITF reached a final consensus in EITF Issue 02-03 "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-03) that states mark-to-market gains and losses on energy trading contracts
(whether realized or unrealized and whether financially or physically settled)
should be shown net in the income statement and that expanded disclosure of
energy trading activities is required. This consensus is effective for periods
ending after July 15, 2002, with reclassification of prior period amounts
required.
The Company currently accounts for all its power and gas marketing contracts at
gross in the Consolidated Condensed Statements of Income. The Company has
reviewed all of its current power marketing contracts and all contracts closed
in prior periods and identified no energy trading contracts subject to EITF
02-03.
SFAS 142
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted the
provisions of SFAS 142, as required on January 1, 2002. SFAS 142 changed the
accounting for goodwill from an amortization approach to an impairment-only
approach. Thus, amortization of goodwill that is not included as an allowable
cost for rate-making purposes ceased upon adoption of this statement. This
includes goodwill recorded in past business combinations, such as the Company's
acquisition of the Ohio operations. Goodwill is to be tested for impairment at a
reporting unit level at least annually.
SFAS 142 also required the initial impairment review of all goodwill within six
months of the adoption date. The impairment review consisted of a comparison of
the fair value of a reporting unit to its carrying amount. If the fair value of
a reporting unit is less than its carrying amount, an impairment loss would be
recognized. Results of the initial impairment review were to be treated as a
change in accounting principle in accordance with APB Opinion No. 20 "Accounting
Changes." An impairment loss recognized as a result of an impairment test
occurring after the initial impairment review is to be reported as a part of
operations. SFAS 142 also changed certain aspects of accounting for other
intangible assets; however, the Company does not have any significant other
intangible assets.
As required by SFAS 142, amortization of goodwill relating to the acquisition of
the Ohio operations, which approximates $5.0 million per year, ceased on January
1, 2002. Initial impairment reviews to be performed within six months of
adoption of SFAS 142 were completed and resulted in no impairment.
SFAS 144
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting
model for all impaired long-lived assets and long-lived assets to be disposed
of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business."
This new accounting model retains the framework of SFAS 121 and requires that
those impaired long-lived assets and long-lived assets to be disposed of be
measured at the lower of carrying amount or fair value (less cost to sell for
assets to be disposed of), whether reported in continuing operations or in
discontinued operations. Therefore, discontinued operations are no longer
measured at net realizable value or include amounts for operating losses that
have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction.
The adoption of SFAS 144 on January 1, 2002 did not materially impact
operations.
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes the
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the impact that SFAS 143 will have on its operations.
Indiana Tax Legislation
The Indiana General Assembly enacted tax-restructuring legislation in June 2002
that included an increase in taxes imposed on income, effectively increasing
Vectren's state income tax rate from 4.5% to 8.5%. Other changes in Indiana tax
provisions include reductions in property taxes and the repeal of the Gross
Income Tax coupled with the enactment of a new Utility Receipts Tax. Although
the new law is not effective until January 1, 2003, the Company reduced
non-regulated earnings by $1.1 million in June 2002 to record recalculated
deferred tax obligations and earnings from leveraged lease investments at the
date of enactment of the law. The impact of the tax rate change on the deferred
taxes of the regulated operations is reflected as a regulatory asset for future
recovery in rates.
Results of Operations by Business Segment
The following is a more detailed discussion of the results of operations of the
Company's regulated and nonregulated businesses. The detailed results of
operations for the regulated businesses and nonregulated businesses are
presented and analyzed before the reclassification and elimination of certain
intersegment transactions necessary to consolidate those results into the
Company's Consolidated Condensed Statements of Income. The operations of the
Corporate and Other business segment, which include primarily information
technology services, are not significant.
Results of Operations of the Regulated Businesses
The Company's regulated operations are comprised of its Gas Utility Services and
Electric Utility Services segments. The Gas Utility Services segment includes
the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas
distribution business and provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and west central Ohio. The Electric
Utility Services segment includes SIGECO's power supply operations, power
marketing operations, and electric transmission and distribution services that
provide electricity to primarily southwestern Indiana.
Operating Results
The results of regulated operations before certain intersegment eliminations and
reclassifications for the three and six months ended June 30, 2002 and 2001 are
as follows:
Three Months Six Months
Ended June 30, Ended June 30,
------------------ ------------------
In millions, except per share amounts 2002 2001 2002 2001
- ------------------------------------------- ------- ------- ------- --------
OPERATING REVENUES
Gas utility $ 139.8 $ 154.6 $ 496.9 $ 678.3
Electric utility 158.9 95.0 285.7 183.2
------- ------- ------- -------
Total operating revenues 298.7 249.6 782.6 861.5
------- ------- ------- -------
COST OF OPERATING REVENUES
Cost of gas 82.2 94.8 312.6 498.9
Fuel for electric generation 19.0 17.8 36.8 35.8
Purchased electric energy 87.0 33.6 146.8 46.8
------- ------- ------- -------
Total cost of operating revenues 188.2 146.2 496.2 581.5
------- ------- ------- -------
TOTAL OPERATING MARGIN 110.5 103.4 286.4 280.0
OPERATING EXPENSES
Other operating 55.3 61.0 111.1 122.8
Merger & integration costs - - - 0.7
Restructuring costs - 10.8 - 10.8
Depreciation & amortization 23.9 24.7 47.5 49.5
Income tax 3.6 (7.3) 25.9 10.5
Taxes other than income taxes 10.2 10.7 28.1 29.8
------- ------- ------- -------
Total operating expenses 93.0 99.9 212.6 224.1
------- ------- ------- -------
OPERATING INCOME 17.5 3.5 73.8 55.9
OTHER INCOME
Equity in earnings of unconsolidated
affiliates (0.4) - (1.0) -
Other - net 8.3 1.1 10.1 0.2
------- ------- ------- -------
Total other income 7.9 1.1 9.1 0.2
------- ------- ------- -------
Interest expense 16.3 17.2 33.2 36.7
Preferred dividend requirement of
subsidiary - 0.3 - 0.5
------- ------- ------- -------
Income (loss) before cumulative effect of
change in accounting principle 9.1 (12.9) 49.7 18.9
------- ------- ------- -------
Cumulative effect of change in accounting
principle - net of tax - - - 3.9
------- ------- ------- -------
NET INCOME (LOSS), AS REPORTED $ 9.1 $ (12.9) $ 49.7 $ 22.8
------- ------- ------- -------
Restructuring costs - net of tax - 6.7 - 6.7
Merger & integration costs - net of tax - 1.7 - 4.0
Cumulative effect of change in accounting
principle - net of tax - - - (3.9)
------- ------- ------- -------
NET INCOME (LOSS) BEFORE NONRECURRING
ITEMS $ 9.1 $ (4.5) $ 49.7 $ 29.6
======= ======= ======= =======
EARNINGS (LOSS) PER SHARE, AS REPORTED $ 0.14 $ (0.19) $ 0.74 $ 0.34
Restructuring costs - 0.10 - 0.10
Merger & integration costs - 0.02 - 0.06
Cumulative effect of change in accounting
principle - - - (0.06)
EARNINGS (LOSS) PER SHARE BEFORE ------- ------- ------- -------
NONRECURRING ITEMS $ 0.14 $ (0.07) $ 0.74 $ 0.44
======= ======= ======= =======
Regulated utility operations contributed net income of $9.1 million, or $0.14
per share, for the three months ended June 30, 2002 compared to a net loss of
$12.9 million, or $0.19 per share for the same period in 2001. The results for
regulated operations increased due to the accrual of carrying costs on the
Company's demand side management programs consistent with an existing IURC rate
order, merger synergies, increased margin due to favorable weather, and the
completion of merger and restructuring activities and related costs.
Regulated utility operations contributed net income of $49.7 million, or $0.74
per share, for the six months ended June 30, 2002 compared to $22.8 million, or
$0.34 per share, for the same period in 2001. In addition to the increases
affecting the quarterly results, the year-to-date period was favorably impacted
by the return to lower gas prices and the related reduction in costs incurred in
2001. These increases were offset by decreased margins from non-firm wholesale
electric sales and the effects of warm weather during the peak heating season.
Utility Margin
Gas Utility Margin
Gas Utility margin for the three months ended June 30, 2002 was favorably
impacted by rate recovery of excise taxes in Ohio effective July 1, 2001, an
increase in the Ohio Percentage of Income Payment Plan (PIPP) rider, customer
growth, and weather considerably cooler during April and May than in the prior
year. The effects of cooler weather and customer growth resulted in an overall
5% increase in total throughput to 35.5 MMDth in 2002 from 33.7 MMDth in 2001.
However, the timing of the cooler weather and other adjustments offset these
factors, resulting in an overall 3.6% decrease in margin when compared to the
prior year.
Total cost of gas sold was $82.2 million for the three months ended June 30,
2002 and $94.8 million in 2001. Total cost of gas sold decreased $12.6 million,
or 13%, during 2002 compared to 2001, primarily due to a return to lower gas
prices. The total average cost per dekatherm of gas purchased for the three
months ended June 30, 2002 was $4.44 compared to $6.03 for the same period in
2001.
Gas Utility margin for the six months ended June 30, 2002 of $184.3 million
increased $4.9 million, or 3%, compared to 2001. The increase is primarily due
to rate recovery of excise taxes in Ohio effective July 1, 2001, an increase in
the PIPP rider and customer growth. These favorable impacts were offset somewhat
by warmer weather compared to the prior year during the peak heating season. The
effects of warmer weather during peak heating periods resulted in an overall 3%
decrease in total throughput to 113.4 MMDth in 2002 from 116.4 MMDth in 2001.
Total cost of gas sold was $312.6 million for the six months ended June 30, 2002
and $498.9 million in 2001. Total cost of gas sold decreased $186.3 million, or
37%, during 2002 compared to 2001, primarily due to a return to lower gas
prices. The total average cost per dekatherm of gas purchased for the six months
ended June 30, 2002 was $4.45 compared to $7.17 for the same period in 2001.
Electric Utility Margin
Electric Utility margin for the three months ended June 30, 2002 of $52.9
million increased $9.3 million, or 21%, from 2001 primarily due to fluctuations
in fair value of derivative contracts. Non-firm wholesale margins in 2001
reflect a $7.9 million reduction due to fair value fluctuations, compared to a
$0.1 million reduction in 2002. The remaining increase, attributable to retail
and firm wholesale sales, results from weather 16% warmer than normal and 10%
warmer than the prior year and a cash return on NOx compliance expenditures
pursuant to a rate recovery rider approved by the IURC in August 2001.
Electric Utility margin for the six months ended June 30, 2002 of $102.1 million
increased $1.5 million, or 1%, from 2001 due to the effects of warmer weather,
offset somewhat by decreases in non-firm wholesale margin.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to better utilize and
optimize the return on these key assets. The contracts entered into are
primarily "buy-sell" transactions, short-term in nature, and expose the Company
to limited market risk. During 2002, the Company has increased its activity in
the wholesale market, as evidenced by increased electric revenues and purchased
power. While volumes both sold and purchased have increased during 2002, margins
have softened this year as a result of reduced price volatility. As a result of
increased activity offset by reduced price volatility, non-firm wholesale power
margins decreased $3.4 million for the year-to-date period.
Utility Operating Expenses
Utility Other Operating
Utility other operating expenses decreased $5.7 million for the three months
ended June 30, 2002 and decreased $11.7 million for the six months ended June
30, 2002 when compared to the prior year periods. The decreases result primarily
from lower charges for the use of corporate assets related to those assets which
had useful lives shortened as a result of the merger. Also contributing to the
decreases are merger synergies, the timing of maintenance expenditures and
increased uncollectible accounts expense in 2001 resulting from high gas costs.
Utility Depreciation & Amortization
Utility depreciation and amortization decreased $0.8 million for the three
months ended June 30, 2002 and decreased $2.0 million for the six months ended
June 30, 2002 when compared to the prior year periods. The decreases result from
the discontinuance of goodwill amortization as required by SFAS 142, offset
somewhat by depreciation of plant additions.
Utility Income Tax Expense
Federal and state income taxes related to utility operations increased $10.9
million for the three months ended June 30, 2002 and increased $15.4 million for
the six months ended June 30, 2002 when compared to the prior year periods. The
increases result from higher pre-tax earnings offset somewhat by a small
decrease in the current year effective tax rate.
Utility Taxes Other Than Income Taxes
Utility taxes other than income taxes decreased $0.5 million for the three
months ended June 30, 2002 and decreased $1.7 million for the six months ended
June 30, 2002 when compared to the prior year periods. The decreases result
primarily from a decrease in gross receipts and excises taxes as a result of
lower gas prices and lower volumes in the six-month period.
Utility Other Income, Net
Utility other income, net increased $7.2 million for the three months ended June
30, 2002 and increased $9.9 million for the six months ended June 30, 2002 when
compared to the prior year periods. The increases are attributable to the
accrual of $5.2 million in carrying costs for demand side management programs
not currently in rates pursuant to an existing IURC rate order and $1.8 million
from the sale of excess emission allowances and other assets. In addition, the
six month period is further affected by 2001 contributions made to low income
heating assistance programs to assist customers with their increased utility
bills reflecting higher gas costs.
Utility Interest Expense
Utility interest expense decreased $0.9 million for the three months ended June
30, 2002 and decreased $3.5 million for the six months ended June 30, 2002 when
compared to the prior year periods. The decreases result from lower interest
rates on variable rate debt and lower outstanding balances. The reduced
short-term debt outstanding is due primarily to decreased working capital
requirements resulting from a return to lower gas prices.
Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the United States Environmental
Protection Agency (USEPA) finds a state's SIP inadequate to achieve the NAAQS,
the USEPA can call upon the state to revise its SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1998 and 1999.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
On August 28, 2001, the IURC issued an order that (1) approved the Company's
proposed project to achieve environmental compliance by investing in clean coal
technology, (2) approved the Company's initial cost estimate of $198 million for
the construction, subject to periodic review of the actual costs incurred, and
(3) approved a mechanism whereby, prior to an electric base rate case, the
Company may recover through a rider that is updated every six months a return on
its capital costs for the project, at its overall cost of capital, including a
return on equity. The first rider adjustment for ongoing cost recovery was
approved by the IURC on February 6, 2002.
The Company has recently filed another proceeding with the IURC to receive
approval of additional capital costs and to obtain approval for recovery of
future operating costs, including depreciation, related to the SCR's through a
rider mechanism. Based on the level of system-wide emissions reductions required
and the control technology utilized to achieve the reductions, the current
estimated construction cost ranges from $240 million to $250 million and is
expected to be expended during the 2001-2006 period. Through June 30, 2002,
$41.0 million has been expended. After the equipment is installed and
operational, related additional annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley is nearing completion on schedule, and
installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. The USEPA alleges that, beginning in 1992, SIGECO violated the
Act by: (1) making modifications to its Culley Generating Station in Yankeetown,
Indiana without obtaining required permits; (2) making major modifications to
the Culley Generating Station without installing the best available emission
control technology; and (3) failing to notify the USEPA of the modifications. In
addition, the lawsuit alleges that the modifications to the Culley Generating
Station required SIGECO to begin complying with federal new source performance
standards at its Culley Unit 3.
SIGECO believes it performed only maintenance, repair and replacement activities
at the Culley Generating Station, as allowed under the Act. Because proper
maintenance does not require permits, application of the best available control
technology, notice to the USEPA, or compliance with new source performance
standards, SIGECO believes that the lawsuit is without merit, and intends to
vigorously defend itself. Since the filing of this lawsuit, the USEPA has
voluntarily dismissed a majority of the claims brought in its original
compliant. In its original complaint, USEPA alleged significant emissions
increases of three pollutants for each of four maintenance projects. Currently,
USEPA is alleging only significant emission increases of a single pollutant at
three of the four maintenance projects cited in the original complaint.
The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per
violation. However, on July 29, 2002, the Court ruled that USEPA could not seek
civil penalties for two of the three remaining projects at issue in the
litigation, significantly reducing potential civil penalty exposure. The lawsuit
also seeks a court order requiring SIGECO to install the best available
emissions technology at the Culley Generating Station. If the USEPA were
successful in obtaining an order, SIGECO estimates that in response it could
incur capital costs of approximately $20 million to $40 million to comply with
the order.
The USEPA has also issued an administrative notice of violation to SIGECO making
the same allegations, but alleging that violations began in 1977.
While it is possible that SIGECO could be subjected to criminal penalties if the
Culley Generating Station continues to operate without complying with the
permitting requirements of new source review and the allegations are determined
by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA
and the electric utility industry have a bonafide dispute over the proper
interpretation of the Act. Accordingly, the Company has recorded no accrual and
the plant continues to operate while the matter is being decided.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by expert consultants, Indiana Gas has accrued
the estimated costs for further investigation, remediation, groundwater
monitoring and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In June of 2002, the Company received a request from the IDEM concerning
information on any manufactured gas plant sites which the Company has not
enrolled in IDEM's Voluntary Remediation Program, specifically five sites which
were owned and/or operated by SIGECO. Preliminary site investigations conducted
by SIGECO in the mid-1990's confirmed that based upon the conditions known at
the time, the sites posed no risk to human health or the environment.
Results of Nonregulated Operations
The Company is involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management, including energy performance contracting services.
Coal Mining mines and sells coal to the Company's utility operations and to
other parties and generates Internal Revenue Service (IRS) Code Section 29
investment tax credits relating to the production of coal-based synthetic fuels.
Utility Infrastructure Services provides underground construction and repair,
facilities locating, and meter reading services. Broadband invests in broadband
communication services such as analog and digital cable television, high-speed
Internet and data services, and advanced local and long distance phone services.
In addition, the nonregulated group has investments in other businesses that
invest in energy-related opportunities and provides utility services, municipal
broadband consulting, retail, and real estate and leveraged lease investments.
Operating Results
The results of nonregulated operations before certain intersegment eliminations
and reclassifications for the three and six months ended June 30, 2002 and 2001
are as follows:
Three Months Six Months
Ended June 30, Ended June 30,
------------------ -------------------
In millions, except per share amounts 2002 2001 2002 2001
- ------------------------------------- ------- -------- -------- --------
Energy services & other revenues $ 88.2 $ 183.5 $ 239.5 $ 455.5
Cost of energy services & other 79.1 177.0 218.5 438.8
------- ------- ------- -------
TOTAL OPERATING MARGIN 9.1 6.5 21.0 16.7
Intersegment revenues, net of costs 0.8 0.5 1.6 0.9
Operating expenses 9.9 7.5 19.0 15.2
Restructuring costs - 0.6 - 0.6
------- ------- ------- -------
OPERATING INCOME (LOSS) - (1.1) 3.6 1.8
------- ------- ------- -------
Other income:
Equity in earnings of unconsolidated
affiliates 4.1 4.4 7.1 10.4
Other - net (0.5) 3.8 0.1 7.4
------- ------- ------- -------
Total other income 3.6 8.2 7.2 17.8
------ ------- ------- -------
Interest expense 2.2 3.3 4.5 6.4
------- ------- ------- -------
INCOME BEFORE TAXES 1.4 3.8 6.3 13.2
------- ------- ------- -------
Income taxes (2.6) (1.1) (2.5) 0.8
Minority interest in subsidiary - (0.2) (0.2) (0.2)
------- ------- ------- -------
INCOME BEFORE EXTRAORDINARY LOSS 4.0 5.1 9.0 12.6
------- ------- ------- -------
Extraordinary loss - net of tax - 7.7 - 7.7
------- ------- ------- -------
NET INCOME (LOSS), AS REPORTED $ 4.0 $ (2.6) $ 9.0 $ 4.9
------- ------- ------- -------
Restructuring costs - net of tax - 0.4 - 0.4
Extraordinary loss - net of tax - 7.7 - 7.7
------- ------- ------- -------
NET INCOME BEFORE NONRECURRING ITEMS $ 4.0 $ 5.5 $ 9.0 $ 13.0
======= ======= ======= =======
EARNINGS (LOSS) PER SHARE, AS REPORTED $ 0.06 $ (0.04) $ 0.13 $ 0.07
Restructuring costs - 0.01 - 0.01
Extraordinary loss - 0.11 - 0.12
-------- ------- ------- -------
EARNINGS PER SHARE BEFORE
NONRECURRING ITEMS $ 0.06 $ 0.08 $ 0.13 $ 0.20
======= ======= ======= =======
For the three and six months ended June 30, 2002, earnings from nonregulated
operations increased $6.6 million, or $0.10 per share, and $4.1, or $0.06 per
share, respectively. The increases are primarily attributable to the
nonrecurring charges incurred during 2001. Earnings before these nonrecurring
charges decreased $1.5 million for the three month period and $4.0 million for
the six month period.
The decrease in the quarter is attributable to a change in Indiana corporate
income tax laws enacted in June 2002, which required the recalculation of
deferred tax obligations and earnings from leveraged lease investments at the
date of enactment of the law, and lower interest and leveraged lease income
resulting from a divestiture of notes receivable and leveraged lease investments
in the second and fourth quarters of 2001, offset by increased earnings from the
Energy Marketing and Services Group. In addition to these factors, the six
months ended June 30, 2002 is also affected by a 2001 after tax gain of $2.4
million from the sale of an investment in a gathering and processing company.
In February 2002, Vectren announced its intention to integrate the operations of
its wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance.
SES provides natural gas and related services to SIGECO and others. Effective
June 1, 2002, the integration was completed. In exchange for the contribution of
SES' net assets totaling $19.4 (including cash of $2.2 million), Vectren's
allocable share of ProLiance's profits and losses increased from 52.5% to 61%,
consistent with Vectren's new ownership percentage. However, governance,
including voting rights, remain at 50% for each member. As governance of
ProLiance remains equal between the members, Vectren continues to account for
its investment in ProLiance using the equity method of accounting.
Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to
June 1, 2002, SES' operating results, now part of ProLiance, are reflected in
equity in earnings of unconsolidated affiliates. The transfer of net assets was
accounted for at book value consistent with joint venture accounting and did not
result in any gain or loss.
Energy Services & Other Revenues
Revenues from Vectren's non-utility operations (primarily the operating
companies of its Energy Marketing and Services, excluding ProLiance which is
reported as equity in earnings of unconsolidated affiliates, as described below,
and Coal Mining groups) for the three and six months ended June 30, 2002
decreased $95.3 million, or 52%, and $216.0 million, or 47%, respectively, when
compared to the prior year. The significant decrease is attributable to Energy
Marketing and Services' natural gas marketing operations, which reflect lower
natural gas prices and exclude SES' June 2002 revenues due to its integration
with ProLiance.
Costs of Energy Services & Other
Cost of energy services and other for the three and six months ended June 30,
2002 decreased $97.9 million and $220.3 million, respectively when compared to
the prior year. These costs are primarily the cost of natural gas purchased for
resale by Energy Marketing and Services' wholly owned gas marketing operations.
The decrease is primarily due to lower per unit purchased gas costs and the
exclusion of SES' June gas costs.
Nonregulated Margin
Margin from nonregulated operations for the three and six months ended June 30,
2002 was $9.1 million and $21.0 million, respectively. The increases of $2.6
million for the three month period and $4.3 million for the six month period
when compared to the prior year periods is primarily due to expanded coal mining
operations adding margin of $1.3 million for the three month period and $3.1
million for the six month period. The increase results from growth in third
party sales and increased capacity. The increased capacity results from the
Company's second mine which began operations in mid 2001. Margins from the
formerly wholly owned natural gas operations of SES increased $1.5 million for
the quarter and $1.8 million year to date. The increase is due to favorable
spreads on gas contracts with sales prices fixed at gas rates existing early in
the year and customer growth. Slight margin increases for both the quarter and
year to date period from performance contracting operations were offset by a
decrease in the operations of the Company's municipal broadband construction and
consulting business.
Nonregulated Operating Expenses
Nonregulated operating expenses consist of other operating expenses,
depreciation and amortization, and taxes other than income taxes. For the three
and six months ended June 30, 2002, nonregulated operating expenses increased
$2.4 million and $3.8 million, respectively. The increases are primarily
attributable to amortization of mine development costs and depreciation of gas
storage fields.
Nonregulated Other Income
Equity in Earnings of Unconsolidated Affiliates
For the three and six months ended June 30, 2002, earnings from unconsolidated
affiliates decreased $0.3 million and $3.3 million, respectively, when compared
to the prior year periods. The decrease for the three month period results from
additional losses incurred by Pace Carbon Synfuels, LP (an investment that
manufactures synthetic-based fuels and qualifies for Internal Revenue Code
Section 29 income tax credits) offset by increases in earnings from Energy
Marketing and Services' investment in ProLiance and from investments in other
businesses that invest in energy-related opportunities. The six-month period is
further affected by a $3.9 million gain recognized in 2001 from the sale of
Haddington Energy Partners, LP's investment in a gathering and processing
company.
Nonregulated Other - Net
For the three and six months ended June 30, 2002, nonregulated other - net
decreased $4.3 million and $7.3 million, respectively, when compared to the
prior year periods. The decrease in both periods is affected by lower interest
and leveraged lease income resulting from a divestiture of notes receivable and
leveraged lease investments in the second and fourth quarters of 2001. In
addition, due to revisions to the Indiana corporate income tax rate enacted in
June 2002, the Company recalculated the earnings of its remaining leveraged
lease investments and recorded a $1.5 million pre-tax adjustment decreasing
leveraged lease income.
Nonregulated Income Tax Expense
For the three and six months ended June 30, 2002, Federal and state income taxes
related to nonregulated operations decreased $1.5 million and $3.3 million,
respectively, when compared to the prior year periods. The decreases result from
lower pre-tax earnings and a lower effective tax rate, offset by the
recalculation of deferred tax liabilities at a newly enacted state rate. The
effective tax rate is lower in 2002 primarily due to the utilization of tax
credits, primarily Internal Revenue Code Section 29 income tax credits generated
from the Company's investment in Pace Carbon Synfuels, LP.
Other Operating Matters
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), began providing
natural gas and related services to Indiana Gas, Citizens Gas, and others in
April 1996. ProLiance also provides services to the Ohio operations and began
providing service to SIGECO in 2002. ProLiance's primary business is optimizing
the gas portfolios of utilities and providing services to large end use
customers.
Regulatory Matters
The sale of gas and provision of other services to Indiana Gas by ProLiance is
subject to regulatory review through the quarterly gas cost adjustment (GCA)
process administered by the IURC. The sale of gas and provision of other
services to the Ohio operations by ProLiance is subject to regulatory review
through the quarterly gas cost recovery (GCR) process administered by the PUCO.
Specific to the sale of gas and provision of other services to Indiana Gas by
ProLiance, on September 12, 1997, the IURC issued a decision finding the gas
supply and portfolio administration agreements between ProLiance and Indiana Gas
and ProLiance and Citizens Gas to be consistent with the public interest and
that ProLiance is not subject to regulation by the IURC as a public utility. The
IURC's decision reflected the significant gas cost savings to customers obtained
through ProLiance's services and suggested that all material provisions of the
agreements between ProLiance and the utilities are reasonable. Nevertheless,
with respect to the pricing of gas commodity purchased from ProLiance, the price
paid by ProLiance to the utilities for the prospect of using pipeline
entitlements if and when they are not required to serve the utilities' firm
customers, and the pricing of fees paid by the utilities to ProLiance for
portfolio administration services, the IURC concluded that additional review in
the GCA process would be appropriate and directed that these matters be
considered further in the pending, consolidated GCA proceeding involving Indiana
Gas and Citizens Gas.
In 2001, the IURC commenced processing the GCA proceeding regarding the three
pricing issues. The IURC indicated that it would consider the prospective
relationship of ProLiance with the utilities in this proceeding. On April 23,
2002, Indiana Gas and Citizens Gas, together with the Office of Utility Consumer
Counselor and other consumer parties, entered into and filed with the IURC an
agreement in principle setting forth the terms for resolution of all pending
regulatory issues related to ProLiance. The parties submitted for IURC approval
a final settlement on June 4, 2002. On July 23, 2002, the IURC approved the
settlement filed by the parties. Any appeal of the IURC's approval order must be
filed by August 23, 2002. The GCA proceeding has been concluded and new supply
agreements between Indiana Gas, SIGECO, Citizens Gas, and ProLiance have been
approved and extended through March 31, 2007. At June 30, 2002 and December 31,
2001, the Company has reserved approximately $4.0 million and $3.2 million,
respectively, of ProLiance's after tax earnings for exposure from this GCA
proceeding. Any additional effect on earnings as a result of the final
settlement for past services provided to Indiana Gas by ProLiance is not
material.
In addition to the above, the IURC order also allows that:
|X| 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.
Pre-tax income of $5.4 million and $4.0 million was recognized as ProLiance's
contribution to earnings for the three months ended June 30, 2002 and 2001,
respectively. Pre-tax income of $10.8 million and $9.6 million was recognized as
ProLiance's contribution to earnings for the six months ended June 30, 2002 and
2001, respectively. Earnings recognized from ProLiance are included in equity in
earnings of unconsolidated affiliates.
Utilicom Networks, LLC
Utilicom Networks, LLC (Utilicom) is a provider of bundled communication
services through high capacity broadband networks, including analog and digital
cable television, high-speed Internet, and advanced local and long distance
phone services. The Company has a 14% interest in Class A units of Utilicom,
which is accounted for using the equity method of accounting. The Company also
has a minority interest in SIGECOM Holdings, Inc., which was formed by Utilicom
to hold interests in SIGECOM, LLC (SIGECOM). The Company accounts for its
investment in Holdings on the cost method. SIGECOM provides broadband services
to the greater Evansville, Indiana, area. Utilicom also plans to provide
broadband services to the greater Indianapolis, Indiana, and Dayton, Ohio,
markets.
In July 2001, Utilicom announced a delay in funding of the Indianapolis and
Dayton projects. This delay, with which Company management agrees, is due to the
continued difficult environment within the telecommunication capital markets,
which has prevented Utilicom from obtaining debt financing on terms it considers
acceptable. While the existing investors are still committed to the Indianapolis
and Dayton markets, the Company is not required to and does not intend to
proceed unless the Indianapolis and Dayton projects are fully funded. This delay
necessitated and resulted in the extension of the franchising agreements into
the third quarter of 2002.
Financial Condition
The Company's equity capitalization objective is 40-50% of total capitalization.
This objective may have varied, and will vary, depending on particular business
opportunities and seasonal factors that affect the Company's operation. The
Company's equity component was 46% and 45% of total capitalization, including
current maturities of long-term debt and long-term debt subject to tender, at
June 30, 2002 and December 31, 2001, respectively.
Short-term cash working capital is required primarily to finance customer
accounts receivable, unbilled utility revenues resulting from cycle billing, gas
in underground storage, prepaid gas delivery services, capital expenditures, and
investments until permanently financed. Short-term borrowings tend to be
greatest during the summer when accounts receivable and unbilled utility
revenues related to electricity are highest and gas storage facilities are being
refilled.
The Company expects the majority of its capital expenditures and debt security
redemptions to be provided by internally generated funds; however, additional
financing may be required in future years due to significant capital expenditure
for NOx compliance equipment at SIGECO.
VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at
March 31, 2002 are A-/A2 as rated by Standard and Poor's and Moody's,
respectively. SIGECO's credit ratings on outstanding secured debt at March 31,
2002 are A-/A1. VUHI's commercial paper has a credit rating of A-2/P-1. Vectren
Capital Corp.'s senior unsecured debt is rated BBB+/Baa2.
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 $255.3
million and $155.6 million for the six months ended June 30, 2002 and 2001,
respectively.
Cash flow from operations increased during the six months ended June 30, 2002
compared to 2001 by $99.7 million due primarily to favorable changes in working
capital accounts due to a return to lower gas prices and increased earnings
before non-cash charges.
Financing Activities
Sources & Uses of Liquidity
At June 30, 2002, the Company had $510.0 million of short-term borrowing
capacity through lines of credit and commercial paper programs, including $330.0
million for its regulated operations and $180.0 million for its wholly-owned
nonregulated and corporate operations, of which $213.8 million was available for
regulated operations and $31.7 million was available for nonregulated and
corporate operations. At June 30, 2002, credit available for nonregulated
operations is reduced by outstanding letters of credit totaling $6.1 million.
During the six months ended June 30, 2002, $1.3 million of long-term debt was
paid as scheduled, and put provisions totaling $5.0 million were exercised.
Other put provisions on long-term debt totaling $6.5 million expired unexercised
during the quarter and have been reclassified as long-term debt.
At June, 2002, $113.0 million of Vectren Capital Corp.'s senior unsecured notes
were subject to certain terms including cross-defaults and ratings triggers that
would provide that the full balance outstanding is subject to prepayment if the
ratings of Indiana Gas and SIGECO declined to BBB/Baa2 or the ratings of Vectren
Capital Corp. declined to BB+/Ba1. Ratings triggers on Vectren Capital Corp.'s
bank loans and VUHI's commercial paper facility existing at December 31, 2001
were removed as facilities were renewed during 2002.
Financing Cash Flow
Cash flow required for financing activities of $157.2 million for the six months
ended June 30, 2002 includes $122.6 million of reductions in net borrowings and
$35.8 million in common stock dividends. In the prior year, $129.4 million of
common stock was issued and used to repay short term borrowings.
Other Financing Transactions
In January 2002, the Company redeemed 1,160 shares of SIGECO's 8.5% preferred
stock per its stated terms of $100 per share, plus accrued and unpaid dividends.
Prior to the redemption, there were 4,597 shares outstanding.
Capital Expenditures, Other Investment Activities, & Guarantees
Cash required for investing activities of $104.1 million for the six months
ended June 30, 2002 includes $94.4 million of requirements for capital
expenditures. Investing activities for the six months ended June 30, 2001 were
$92.6 million. The $11.5 million increase occurring in 2002 is principally the
result of more capital expenditure for utility plant and other nonregulated
investments.
Planned Capital Expenditures
New construction, normal system maintenance and improvements, and information
technology investments needed to provide service to a growing regulated and
nonregulated customer base will continue to require substantial expenditures.
Investments in nonregulated unconsolidated affiliates and company-wide capital
expenditures for the remainder of 2002 are estimated at $118.6 million.
Guarantees
The Company is party to financial guarantees with off-balance sheet risk. These
guarantees include debt guarantees and performance guarantees, including the
debt of and performance of energy efficiency products installed by affiliated
companies. The Company estimates these totaled approximately $90 million at June
30, 2002. The Company's most significant guarantee totaling $58.2 million at
June 30, 2002 represents two-thirds of Energy Systems Group, LLC's (ESG) surety
bonds, performance and energy savings guarantees. ESG is a two-thirds owned
consolidated subsidiary. The guarantees relate to amounts due to various
insurance companies for surety bonds should ESG default on obligations to
complete construction, pay vendors or subcontractors, and achieve energy
guarantees. Through June 30, 2002, the Company has not been called upon to
satisfy any obligations pursuant to the guarantees.
Forward-Looking Information
A "safe harbor" for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management's Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management's beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words "believe," "anticipate,"
"endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal,"
and similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements included, among others, the following:
|X| Factors affecting utility operations such as unusual weather
conditions; catastrophic weather-related damage; unusual maintenance
or repairs; unanticipated changes to fossil fuel costs; unanticipated
changes to gas supply costs, or availability due to higher demand,
shortages, transportation problems or other developments;
environmental or pipeline incidents; transmission or distribution
incidents; unanticipated changes to electric energy supply costs, or
availability due to demand, shortages, transmission problems or other
developments; or electric transmission or gas pipeline system
constraints.
|X| Increased competition in the energy environment including effects of
industry restructuring and unbundling.
|X| Regulatory factors such as unanticipated changes in rate-setting
policies or procedures, recovery of investments and costs made under
traditional regulation, and the frequency and timing of rate
increases.
|X| Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission, state public
utility commissions, state entities which regulate natural gas
transmission, gathering and processing, and similar entities with
regulatory oversight.
|X| Economic conditions including the effects of an economic downturn,
inflation rates, and monetary fluctuations.
|X| Changing market conditions and a variety of other factors associated
with physical energy and financial trading activities including, but
not limited to, price, basis, credit, liquidity, volatility, capacity,
interest rate, and warranty risks.
|X| Availability or cost of capital, resulting from changes in the
Company, including its security ratings, changes in interest rates,
and/or changes in market perceptions of the utility industry and other
energy-related industries.
|X| Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages.
|X| Legal and regulatory delays and other obstacles associated with
mergers, acquisitions, and investments in joint ventures.
|X| Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims, and other matters, including, but
not limited to, those described in Management's Discussion and
Analysis of Results of Operations and Financial Condition.
|X| Changes in federal, state or local legislature requirements, such as
changes in tax laws or rates, environmental laws and regulations.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of changes in actual results,
changes in assumptions, or other factors affecting such statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program.
Commodity Price Risk
The Company's regulated operations have limited exposure to commodity price risk
for purchases and sales of natural gas and electric energy for its retail
customers due to current Indiana and Ohio regulations, which subject to
compliance with applicable state regulations, allow for recovery of such
purchases through natural gas and fuel cost adjustment mechanisms.
The Company does engage in limited wholesale power marketing and other marketing
activities that may expose it to commodity price risk associated with
fluctuating electric power, natural gas, and coal commodity prices.
The Company's wholesale power marketing activities manage the utilization of its
available electric generating capacity. The Company's other commodity marketing
activities purchase and sell natural gas and coal to meet customer demands.
These operations enter into forward and option contracts that commit the Company
to purchase and sell commodities in the future. As a result of the integration
of the Company's wholly owned subsidiary, SIGCORP Energy Services, LLC, into
ProLiance Energy, LLC, a 61% owned joint venture accounted for using the equity
method, any natural gas marketing is now conducted by ProLiance.
Commodity price risk results from forward sale and option contracts that commit
the Company to deliver commodities on specified future dates. Power marketing
uses planned unutilized generation capability and forward purchase contracts to
protect certain sales transactions from unanticipated fluctuations in the price
of electric power, and periodically, will use derivative financial instruments
to protect its interests from unplanned outages and shifts in demand.
Additionally, other commodity marketing activities use stored inventory and
forward purchase contracts to protect certain sales transactions from
unanticipated fluctuations in commodity prices.
Open positions in terms of price, volume and specified delivery points may occur
to a limited extent and are managed using methods described above and frequent
management reporting.
When generation capacity is not needed to serve utility customers, the Company
markets available power from its owned generation assets to better utilize and
optimize the return on these key assets. The contracts entered into are
primarily "buy-sell" transactions, short-term in nature, and expose the Company
to limited market risk. During 2002, the Company has increased its activity in
the wholesale market. With the exception of those contracts subject to the
normal purchase and sale exclusion, commodity contracts are accounted for at
market value. As of June 30, 2002, contracts had a net asset value of $0.1
million compared to a net asset value of $3.2 million at December 31, 2001. The
Company has determined these energy marketing contracts are derivatives within
the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities."
Power marketing contracts at June 30, 2002 totaled $9.7 million of prepayments
and other current assets and $9.6 million of accrued liabilities, compared to
$5.2 million of prepayments and other current assets and $2.0 million of accrued
liabilities at December 31, 2001. The change in the net value of these contracts
to $0.1 million at June 30, 2002 from $3.2 million at December 31, 2001 resulted
in an unrealized loss of $0.1 million and $3.1 million, respectively, for the
three and six months ended June 30, 2002. For the three and six months ended
June 30, 2001, the Company's power marketing operations resulted in unrealized
losses of $7.9 million and $2.4 million, respectively. Including these
unrealized changes in fair value, overall margin (revenue net of purchased
power) from power marketing operations for the three and six months ended June
30, 2002 was $2.4 million and $3.4 million, respectively, and for the three and
six months ended June 30, 2001 was ($4.6) million and $6.8 million,
respectively.
Market risk is measured by management as the potential impact on pre-tax
earnings resulting from a 10% adverse change in the forward price of commodity
prices on market sensitive financial instruments (all contracts not expected to
be settled by physical receipt or delivery). For the three and six months ended
June 30, 2002, a 10% adverse change in the forward prices of electricity on
market sensitive financial instruments would have decreased pre-tax earnings by
approximately $0.1 million and $1.5 million, respectively. For the three and six
months ended June 30, 2001, a 10% adverse change in the forward prices of
electricity on market sensitive financial instruments would have decreased
pre-tax earnings by approximately $0.6 million and $1.4 million, respectively.
Commodity Price Risk from Unconsolidated Affiliate
Commodity price risk from an unconsolidated affiliate is not significantly
different from the information as set forth in Item 7A. Quantitative and
Qualitative Disclosures About Market Risk included in the Vectren 2001 Form 10-K
and is therefore not presented herein.
Interest Rate Risk
Interest rate risk is not significantly different from the information as set
forth in Item 7A. Quantitative and Qualitative Disclosures About Market Risk
included in the Vectren 2001 Form 10-K and is therefore not presented herein.
Other Risks
By using forward purchase contracts and derivative financial instruments to
manage risk, the Company exposes itself to counter-party credit risk and market
risk. The Company manages this exposure to counter-party credit risk by entering
into contracts with companies that can be reasonably expected to fully perform
under the terms of the contract. Counter-party credit risk is monitored
regularly and positions are adjusted appropriately to manage risk. Further,
tools such as netting arrangements and requests for collateral are also used to
manage credit risk. The Company attempts to manage exposure to market risk
associated with commodity contracts and interest rates by establishing and
monitoring parameters that limit the types and degree of market risk that may be
undertaken.
The Company's customer receivables from gas and electric sales and gas
transportation services are primarily derived from a diversified base of
residential, commercial, and industrial customers located in Indiana and west
central Ohio. The Company manages credit risk associated with its receivables by
continually reviewing creditworthiness and requests cash deposits based on that
review. Credit risk associated with certain investments is also managed by a
review of creditworthiness and receipt of collateral.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is party to various legal and regulatory proceedings arising in the
normal course of business. In the opinion of management, there are no legal
proceedings pending against the Company that are likely to have a material
adverse effect on its financial position or results of operations. See Note 8
regarding environmental matters and Note 7 regarding ProLiance Energy, LLC.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Vectren's Annual Meeting of Stockholders was held on April 24, 2002.
At said Annual Meeting, the stockholders elected these Directors by the
following votes:
Director Votes For Votes Against Abstentions
-------------------- ---------- ------------- -----------
Lawrence A. Ferger 59,135,956 0 1,303,627
Ronald G. Reherman 59,099,654 0 1,339,929
Richard W. Shymanski 59,106,689 0 1,332,894
Jean L. Wojtowicz 58,988,648 0 1,450,935
The terms of office of John M. Dunn, Niel C. Ellerbrook, John D. Engelbrecht,
Anton H. George, Andrew E. Goebel, Robert L. Koch II, William G. Mays, J.
Timothy McGinley, and Richard P. Rechter will expire in 2003 or 2004.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None
(b) Reports On Form 8-K During The Last Calendar Quarter
On April 25, 2002, Vectren Corporation filed a Current Report on Form 8-K with
respect to the release of financial information to the investment community
regarding the Company's results of operations, financial position and cash flows
for the three and twelve month periods ended March 31, 2002. The financial
information was released to the public through this filing.
Item 5. Other Events
Item 7. Exhibits
99.1 - Press Release - First Quarter 2002 Vectren
Corporation Earnings
99.2 - Cautionary Statement for Purposes of the "Safe
Harbor" Provisions of the Private Securities
Litigation Reform Act of 1995
On April 25, 2002, Vectren Corporation filed a current report on From 8-K with
respect to the filing of an agreement with the Indiana Utility Regulatory
Commission setting forth the basic framework for an anticipated settlement of
numerous pending issues related to ProLiance Energy, LLC
Item 5. Other Events
Item 7. Exhibits
99-1 Press Release - Consumer Groups and Utilities Announce
Proposed Agreement on Gas Supply Services from
ProLiance
On May 20, 2002, Vectren Corporation filed an amendment to current report on
Form 8-K, originally filed on March 26, 2002, with respect to its decision to
dismiss Arthur Andersen LLP as the independent auditors of Vectren Corporation
effective May 17, 2002. Deloitte & Touche LLP has been selected as the
independent auditor for the company effective May 17, 2002.
Item 4. Changes in Registrant's Certifying Accountant.
Item 7. Exhibits.
16 - Letter from Arthur Andersen LLP to the Securities and
Exchange Commission, dated May 20, 2002.
99 - Press release regarding selection of Deloitte &
Touche LLP dated May 20, 2002.
On May 23, 2002 Vectren Corporation filed a current report on Form 8-K with
respect to its decision to dismiss Arthur Andersen LLP as the independent
auditors of the Vectren Corporation Retirement Savings Plan (the Plan) effective
May 17, 2002. McGladrey & Pullen, LLP has been selected as the independent
auditor for the plan effective May 17, 2002.
Item 4. Changes in Registrant's Certifying Accountant.
Item 7. Exhibits.
16 - Letter from Arthur Andersen LLP to the Securities and
Exchange Commission, dated May 23, 2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
VECTREN CORPORATION
-------------------------
Registrant
August 14, 2002 /s/Jerome A. Benkert, Jr.
-------------------------
Jerome A. Benkert, Jr.
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/M. Susan Hardwick
-------------------------
M. Susan Hardwick
Vice President and Controller
(Principal Accounting Officer)
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
By signing below, each of the undersigned officers hereby certifies pursuant to
18 U.S.C. ss. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, that, to his or her knowledge, (i) this report fully complies with the
requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
and (ii) the information contained in this report fairly presents, in all
material respects, the financial condition and results of operations of Vectren
Corporation.
Signed this 14th day of August, 2002.
/s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook
- ---------------------------------- -----------------------------------
(Signature of Authorized Officer) (Signature of Authorized Officer)
Jerome A. Benkert, Jr. Niel C. Ellerbrook
- ---------------------------------- -----------------------------------
(Typed Name) (Typed Name)
Executive Vice President and
Chief Financial Officer Chairman and Chief Executive Officer
- ---------------------------------- ------------------------------------
(Title) (Title)