UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
|
ý
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
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For
the fiscal year ended December 31, 2006
OR
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
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For
the
transition period from __________________ to
________________________
Commission
file number: 1-15467
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VECTREN
CORPORATION
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(Exact
name of registrant as specified in its charter)
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INDIANA
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35-2086905
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(State
or other jurisdiction of incorporation or organization)
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(IRS
Employer Identification No.)
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One
Vectren Square
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47708
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|
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant's
telephone number, including area code: 812-491-4000
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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Common
- Without Par
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New
York Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act: NONE
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act.
Yes ý No□
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d0 of the Act. Yes □
No
ý
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 ý.
No
□
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this
Form 10-K. □
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filer ý Accelerated
filer □ Non-accelerated
filer □
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes
□
No
ý
The
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity
was
last sold, or the average bid and asked price of such common equity, as of
June
30, 2006, was $2,056,925,411.
Indicate
the number of shares outstanding of each of the registrant's classes of common
stock, as of the latest practicable date.
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Common
Stock - Without Par Value
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76,252,552
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January
31, 2007
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Class
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Number
of Shares
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Date
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Documents
Incorporated by Reference
Certain
information in the Company's definitive Proxy Statement for the 2007 Annual
Meeting of Stockholders, which will be filed with the Securities and Exchange
Commission pursuant to Regulation 14A, not later than 120 days after the end
of
the fiscal year, is incorporated by reference in Part III of this Form 10-K.
Definitions
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AFUDC:
allowance for funds used during construction
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MMBTU:
millions of British thermal units
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APB:
Accounting Principles Board
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MW:
megawatts
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EITF:
Emerging Issues Task Force
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MWh
/ GWh: megawatt hours / thousands of megawatt hours (gigawatt
hours)
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FASB:
Financial Accounting Standards Board
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NOx:
nitrogen oxide
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FERC:
Federal Energy Regulatory Commission
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OUCC:
Indiana Office of the Utility Consumer Counselor
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IDEM:
Indiana Department of Environmental Management
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PUCO:
Public Utilities Commission of Ohio
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IURC:
Indiana Utility Regulatory Commission
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SFAS:
Statement of Financial Accounting Standards
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MCF
/ BCF: thousands / billions of cubic feet
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USEPA:
United States Environmental Protection Agency
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MDth
/ MMDth: thousands / millions of dekatherms
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Throughput:
combined gas sales and gas transportation
volumes
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Item
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Page
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|||||
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Number
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Number
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|||||
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Part
I
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||||||
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1
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Business
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4
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||||
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1A
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Risk
Factors
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10
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||||
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1B
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Unresolved
Staff Comments
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14
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||||
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2
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Properties
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14
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||||
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3
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Legal
Proceedings
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16
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||||
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4
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Submission
of Matters to Vote of Security Holders
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16
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Part
II
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||||||
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5
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Market
for the Company’s Common Equity, Related Stockholder Matters, and Issuer
Purchases of Equity Securities
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16
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||||
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6
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Selected
Financial Data
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17
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||||
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7
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Management's
Discussion and Analysis of Results of Operations and Financial
Condition
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18
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7A
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Qualitative
and Quantitative Disclosures About Market Risk
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43
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||||
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8
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Financial
Statements and Supplementary Data
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45
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9
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Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
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88
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9A
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Controls
and Procedures, including Management’s Assessment of Internal Controls
over Financial ReportingControls
and Procedures
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88
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9B
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Other
Information
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88
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||||||
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Part
III
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||||||
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10
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Directors,
Executive Officers and Corporate Governance
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88
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11
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Executive
Compensation
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89
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12
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters.
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89
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13
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Certain
Relationships, Related Transactions and Director
Independence
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89
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14
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Principal
Accountant Fees and Services
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90
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||||||
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Part
IV
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||||||
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15
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Exhibits
and Financial Statement Schedules
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90
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Signatures
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95
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Access
to Information
Vectren
Corporation makes available all SEC filings and recent annual reports free
of
charge through its website at www.vectren.com, or by request, directed to
Investor Relations at the mailing address, phone number, or email address that
follows:
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Mailing
Address:
One
Vectren Square
Evansville,
Indiana 47708
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Phone
Number:
(812)
491-4000
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Investor
Relations Contact:
Steven
M. Schein
Vice
President, Investor Relations
sschein@vectren.com
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||
PART
I
ITEM
1. BUSINESS
Description
of the Business
Vectren
Corporation (the Company or Vectren), an Indiana corporation, is an energy
holding company headquartered in Evansville, Indiana. The Company’s wholly owned
subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the
intermediate holding company for three operating public utilities: Indiana
Gas
Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO),
and the Ohio operations. Utility Holdings also has other assets that provide
information technology and other services to the three utilities. Utility
Holdings’ consolidated operations are collectively referred to as the Utility
Group. Both Vectren and Utility Holdings were exempt from registration pursuant
to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935,
which was repealed effective February 8, 2006 by the Energy Policy Act of 2005
(Energy Act). Both Vectren and Utility Holdings are holding companies as defined
by the Energy Act. Vectren
was incorporated under the laws of Indiana on June 10, 1999.
Indiana
Gas provides energy delivery services to approximately 565,000 natural gas
customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 141,000 electric customers and approximately
112,000 gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers
and
optimizes those assets in the wholesale power market. Indiana Gas and SIGECO
generally do business as Vectren Energy Delivery of Indiana. The Ohio operations
provide energy delivery services to approximately 318,000 natural gas customers
located near Dayton in west central Ohio. The Ohio operations are owned as
a
tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly
owned subsidiary of Utility Holdings (53% ownership), and Indiana Gas (47%
ownership). The Ohio operations generally do business as Vectren Energy Delivery
of Ohio.
The
Company, through Vectren Enterprises, Inc. (Enterprises), is also involved
in
nonutility activities in three primary business areas: Energy Marketing and
Services, Coal Mining and Energy Infrastructure Services. Energy Marketing
and
Services markets and supplies natural gas and provides energy management
services. Coal Mining mines and sells coal. Energy Infrastructure Services
provides underground construction and repair and energy performance contracting
services. Enterprises also has other businesses that invest in energy-related
opportunities and services, real estate, and leveraged leases, among other
investments. In addition, the Company has investments that generate synfuel
tax credits and processing fees relating to the production of coal-based
synthetic fuels. These operations are collectively referred to as the
Nonutility Group.
Enterprises supports the Company’s regulated utilities pursuant to service
contracts by providing natural gas supply services, coal, infrastructure
services, and other services.
Narrative
Description of the Business
The
Company segregates its operations into three groups: a Utility Group, a
Nonutility Group, and Corporate and Other. At December 31, 2006, the Company
had
$4.1 billion in total assets, with $3.4 billion (84%) attributed to the Utility
Group, $0.6 billion (16%) attributed to the Nonutility Group, and less than
$0.1
billion attributed to Corporate and Other. Net income for the year ended
December 31, 2006, was $108.8 million, or $1.44 per share of common stock,
with
$91.4 million attributed to the Utility Group, $18.1 million attributed to
the
Nonutility Group, and a net loss of $0.7 million attributed to Corporate and
Other. Net income for the year ended December 31, 2005, was $136.8 million,
or
$1.81 per share of common stock. For further information regarding the
activities and assets of operating segments within these Groups, refer to Note
16 in the Company’s consolidated financial statements included under “Item 8
Financial Statements and Supplementary Data.”
Following
is a more detailed description of the Utility Group and Nonutility Group.
Corporate and Other operations are not significant.
Utility
Group
The
Utility Group is comprised of Utility Holdings’ operations. The operations of
the Utility Group consist of the Company’s regulated operations and other
operations that provide information technology and other support services to
those regulated operations. The Company segregates its regulated operations
into
a Gas Utility Services operating segment and an Electric Utility Services
operating segment. 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 to west central Ohio. The Electric Utility Services
segment includes the operations of SIGECO’s electric transmission and
distribution services, which provides electric distribution services primarily
to southwestern Indiana, and includes the Company’s power generating and asset
optimization operations. In total, these regulated operations supply natural
gas
and/or electricity to over one million customers. The Utility Group’s other
operations are not significant.
Gas
Utility Services
At
December 31, 2006, the Company supplied natural gas service to approximately
995,000 Indiana and Ohio customers, including 909,000 residential, 84,000
commercial, and 2,000 industrial and other contract customers. This represents
customer base growth of 0.3% compared to 2005.
The
Company’s service area contains diversified manufacturing and
agriculture-related enterprises. The principal industries served include
automotive assembly, parts and accessories, feed, flour and grain processing,
metal castings, aluminum products, appliance manufacturing, polycarbonate resin
(Lexan®) and plastic products, gypsum products, electrical equipment, metal
specialties, glass, steel finishing, pharmaceutical and nutritional products,
gasoline and oil products, and coal mining. The largest Indiana communities
served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington,
Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, Richmond,
and suburban areas surrounding Indianapolis. The largest community served
outside of Indiana is Dayton, Ohio.
Revenues
For
the
year ended December 31, 2006, gas utility revenues were approximately $1,232.5
million, of which residential customers accounted for 66%, commercial 28%,
and
industrial and other contract customers 6%.
The
Company receives gas revenues by selling gas directly to customers at approved
rates or by transporting gas through its pipelines at approved rates to
customers that have purchased gas directly from other producers, brokers, or
marketers. Total volumes of gas provided to both sales and transportation
customers (throughput) were 182.6 MMDth for the year ended December 31, 2006.
Gas transported or sold to residential and commercial customers was 97.7 MMDth
representing 53% of throughput. Gas transported or sold to industrial and other
contract customers was 84.9 MMDth representing 47% of throughput. Rates for
transporting gas generally provide for the same margins earned by selling gas
under applicable sales tariffs.
The
sale
of gas is seasonal and strongly affected by variations in weather conditions.
To
mitigate seasonal demand, the Company has storage capacity at seven active
underground gas storage fields and six liquefied petroleum air-gas manufacturing
plants. The Company also contracts with its affiliate, ProLiance Energy, LLC
(ProLiance), and with other third party gas service providers to ensure
availability of gas. ProLiance is an unconsolidated, nonutility, energy
marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens
Gas).
(See the discussion of Energy Marketing & Services below and Note 3 in the
Company’s consolidated financial statements included in “Item 8 Financial
Statements and Supplementary Data” regarding transactions with ProLiance).
Periodically, purchased natural gas is injected into storage. The injected
gas
is then available to supplement contracted and manufactured volumes during
periods of peak requirements. In lieu of storage, the Company prepays ProLiance
for natural gas delivery services during the seven months prior to the peak
heating season. The volumes of gas per day that can be delivered during peak
demand periods for each utility are located in “Item 2 Properties.”
Gas
Purchases
In
2006,
the Company purchased 95,561 MDth volumes of gas at an average cost of $8.64
per
Dth, of which approximately 72% was purchased from ProLiance and 28% was
purchased from other third party providers. Vectren received regulatory approval
on April 25, 2006 from the IURC for ProLiance to provide natural gas supply
services to the Company’s Indiana utilities through March 2011. As a result of
the June 2005 PUCO order, the Company has established an annual bidding process
for VEDO’s gas supply and portfolio administration services. Since November 1,
2005, the Company has used a third party provider for these services. Prior
to
October 31, 2005, ProLiance supplied natural gas to all of the Company’s
regulated gas utilities. The average cost of gas per Dth purchased for the
previous five years was $8.64 in 2006; $9.05 in 2005; $6.92 in 2004; $6.36
in
2003; and $4.57 in 2002.
Electric
Utility Services
At
December 31, 2006, the Company supplied electric service to approximately
141,000 Indiana customers, including 122,000 residential, 18,800 commercial,
and
200 industrial and other customers. This represents customer base growth of
1%
compared to 2005. In addition, the Company has firm power commitments to four
municipalities and has contingency reserve requirements consistent with
Reliability First Corp. standards.
The
principal industries served include polycarbonate resin (Lexan®) and plastic
products, aluminum smelting and recycling, aluminum sheet products, automotive
assembly, steel finishing, appliance manufacturing, pharmaceutical and
nutritional products, automotive glass, gasoline and oil products, and coal
mining.
Revenues
For
the
year ended December 31, 2006, retail and firm wholesale electricity sales
totaled 6,004.5 GWh, resulting in revenues of approximately $392.5 million.
Residential customers accounted for 25% of 2006 revenues; commercial 22%;
industrial 43%; and municipal and other 10%. In addition, the Company sold
898.3
GWh through optimization activities in 2006, generating revenue, net of
purchased power costs, of $29.7 million.
Generating
Capacity
Installed
generating capacity as of December 31, 2006, was rated at 1301 MW. Coal-fired
generating units provide 1,006 MW of capacity, and natural gas or oil-fired
turbines used for peaking or emergency conditions provide 295 MW.
In
addition to its generating capacity, in 2006, the Company had 34 MW available
under firm contracts and 62 MW available under interruptible contracts. The
Company also had a firm purchase supply contract for a maximum of 73 MW for
the
cooling season months during 2006. This contract ended at the end of September
2006. Also, under the terms of the consent decree between SIGECO, the Department
of Justice and USEPA, the Company discontinued operations of Culley Unit 1
(50
MW) effective December 31, 2006. The Company executed a capacity contract for
a
maximum of 100 MW for the years 2007-2009.
The
Company has interconnections with Louisville Gas and Electric Company, Cinergy
Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural
Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of
Jasper, Indiana, providing the historic ability to simultaneously interchange
approximately 500 MW. However, the ability of the Company to effectively utilize
the electric transmission grid in order to achieve its desired import/export
capability has been, and may continue to be, impacted as a result of the ongoing
changes in the operation of the midwestern transmission grid. The Company,
as a
member of the Midwest Independent System Operator (MISO), has turned over
operational control of the interchange facilities and its own transmission
assets, like many other Midwestern electric utilities, to MISO. See “Item 7
Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s participation in MISO.
Total
load for each of the years 2002 through 2006 at the time of the system summer
peak, and the related reserve margin, is presented below in MW.
|
Date
of summer peak load
|
8/10/2006
|
|
7/25/2005
|
|
7/13/2004
|
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8/27/2003
|
|
8/5/2002
|
|
|
Total
load at peak (1)
|
1,325
|
|
1,315
|
|
1,222
|
|
1,272
|
|
1,258
|
|
|
Generating
capability
|
1,351
|
|
1,351
|
|
1,351
|
|
1,351
|
|
1,351
|
|
|
Firm
purchase supply
|
107
|
|
107
|
|
105
|
|
32
|
|
82
|
|
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Interruptible
contracts
|
62
|
|
76
|
|
51
|
|
95
|
|
95
|
|
|
Total
power supply capacity
|
1,520
|
|
1,534
|
|
1,507
|
|
1,478
|
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1,528
|
|
|
Reserve
margin at peak
|
15%
|
|
17%
|
|
23%
|
|
16%
|
|
21%
|
| (1) |
The
total load at peak is increased 25 MW in 2006, 2005, 2003, and 2002
from
the total load actually experienced. The additional 25 MW represents
load
that would have been incurred if Summer Cycler program had not been
activated. The 25 MW is also included in the interruptible contract
portion of the Company’s total power supply capacity in those years. On
the date of peak in 2004, Summer Cycler program was not
activated.
|
The
winter peak load for the 2005-2006 season of approximately 935 MW occurred
on
December 20, 2005. The prior year winter peak load was approximately 932 MW,
occurring on January 18, 2005.
The
Company maintains a 1.5% interest in the Ohio Valley Electric Corporation
(OVEC). The OVEC is comprised of several electric utility companies, including
SIGECO, and supplies power requirements to the United States Department of
Energy’s (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating
companies are entitled to receive from OVEC, and are obligated to pay for,
any
available power in excess of the DOE contract demand. At the present time,
the
DOE contract demand is essentially zero. Because of this decreased demand,
the
Company’s 1.5% interest in the OVEC makes available approximately 34 MW of
capacity for use in other operations. Such generating capacity is included
in
firm purchase supply in the chart above.
Fuel
Costs and Purchased Power
Electric
generation for 2006 was fueled by coal (98%) and natural gas (2%). Oil was
used
only for testing of gas/oil-fired peaking units.
There
are
substantial coal reserves in the southern Indiana area, and coal for coal-fired
generating stations has been supplied from operators of nearby Indiana coal
mines, including those owned by Vectren Fuels, Inc., a wholly owned subsidiary
of the Company. Approximately 3.5 million tons of coal were purchased for
generating electricity during 2006, of which approximately 91% was supplied
by
Vectren Fuels, Inc. from its mines and third party purchases. The average cost
of coal consumed in generating electric energy for the years 2002 through 2006
follows:
|
Year
Ended December 31,
|
||||||||||
|
Avg.
Cost Per
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
|
Ton
|
|
$
37.51
|
|
$
30.27
|
|
$
27.06
|
|
$
24.91
|
|
$
23.50
|
|
MWh
|
|
18.44
|
|
14.94
|
|
13.06
|
|
11.93
|
|
11.00
|
The
Company also purchases power as needed from the wholesale market to supplement
its generation capabilities in periods of peak demand; however, the majority
of
power purchased through the wholesale market is used to optimize and hedge
the
Company’s sales to other wholesale customers. Volumes purchased in 2006
totaled 434,234 MWh.
Competition
The
utility industry has undergone dramatic structural change for several years,
resulting in increasing competitive pressures faced by electric and gas utility
companies. Currently, several states, including Ohio, have passed legislation
allowing electricity customers to choose their electricity supplier in a
competitive electricity market and several other states are considering such
legislation. At the present time, Indiana has not adopted such legislation.
Ohio
regulation allows gas customers to choose their commodity supplier. The Company
implemented a choice program for its gas customers in Ohio in January 2003.
At
December 31, 2006, over 72,000 customers in Vectren’s Ohio service territory
purchase natural gas from a supplier other than the utility. Margin earned
for
transporting natural gas to those customers, who have purchased natural gas
from
another supplier, are generally the same as those earned by selling gas under
Ohio tariffs. Indiana has not adopted any regulation requiring gas choice;
however, the Company operates under approved tariffs permitting large volume
customers to choose their commodity supplier.
Regulatory
and Environmental Matters
See
“Item
7 Management’s Discussion and Analysis of Results of Operations and Financial
Condition” regarding the Company’s regulated environment and other environmental
matters.
Nonutility
Group
The
Company is involved in nonutility activities in three primary business areas:
Energy Marketing and Services, Coal Mining, and Energy Infrastructure Services.
Energy
Marketing and Services
The
Energy Marketing and Services group relies heavily on a customer focused, value
added strategy in three areas: gas marketing, energy management, and retail
gas
supply.
ProLiance
ProLiance,
a nonutility gas marketing and energy management affiliate of Vectren and
Citizens Gas and Coke Utility (Citizens Gas), provides services to a broad
range
of municipalities, utilities, industrial operations, schools, and healthcare
institutions located throughout the Midwest and Southeast United States.
ProLiance’s primary customers include Vectren’s Indiana utilities and nonutility
gas supply operations as well as Citizens Gas. ProLiance’s primary businesses
include gas marketing, gas portfolio optimization, and other portfolio and
energy management services. The Company, including its retail gas supply
operations, contracted for 75% of its natural gas purchases through ProLiance
in
2006.
In
2002,
the Company integrated a wholly owned subsidiary, SIGCORP Energy Services,
LLC
(SES), with ProLiance. SES provided natural gas and related services to SIGECO
and others prior to the transaction. In exchange for the contribution of SES’
net assets totaling $19.2 million, Vectren’s allocable share of ProLiance’s
profits and losses increased from 52.5% to 61%, consistent with Vectren’s
current ownership percentage. In March 2001, Vectren’s allocable share of
profits and losses increased from 50% to 52.5% when ProLiance began managing
the
Ohio operations’ gas portfolio. Governance and voting rights remain at 50% for
each member; and therefore, Vectren continues to account for its investment
in
ProLiance using the equity method of accounting.
For
the
year ended December 31, 2006, ProLiance’s revenues, including sales to Vectren
companies, exceeded $2.5 billion.
At
December 31, 2006, the pre-tax earnings of ProLiance exceeded 20% of Vectren’s
pre-tax earnings and, as a result, ProLiance is a “significant subsidiary”
within the meaning of Regulation S-X, paragraph 3-09. As such, ProLiance’s
audited financial statements as of and for its fiscal years ending September
30,
2006, 2005, and 2004, are included in this Form 10-K.
Vectren
Source
Vectren
Retail, LLC (d/b/a Vectren Source) provides natural gas and other related
products and services in the Midwest and Southeast United States to 150,000
residential and commercial customers opting for choice among energy providers.
Vectren Source generated approximately $162.5 million in revenues in 2006,
up
from $129.2 million in 2005. Gas sold approximated 12,228 MDth in 2006, 12,411
MDth in 2005 and 9,386 MDth in 2004.
Coal
Mining
The
Coal
Mining group mines and sells coal to the Company’s utility operations and to
third parties through its wholly owned subsidiary Vectren Fuels, Inc (Fuels).
The Company’s two coal mines produced 4.0 million tons in 2006, compared to 4.4
million tons in 2005 and 3.6 million tons in 2004.
In
April
2006, Fuels secured the rights to open two new underground mines near Vincennes,
Indiana. The first mine is expected to be operational by early 2009, with the
second mine opening the following year. Reserves at the two mines are estimated
at 80 million tons of recoverable number-five coal at 11,200 BTU (British
thermal units) and 6-pound sulfur dioxide. Management estimates a $125 million
investment to access the reserves. Once in full production, the two new mines
are expected to produce 5 million tons of coal per year.
Energy
Infrastructure Services
Energy
Infrastructure Services provides energy performance contracting operations
through Energy Systems Group, LLC (ESG) and natural gas and water
distribution, transmission, construction repair and rehabilitation as well
as
the repair and rehabilitation of gas, water, and wastewater facilities through
Miller Pipeline Corporation (Miller). Miller's customers include Vectren’s
utilities.
Energy
Systems Group
Performance-based
energy contracting operations are performed through Energy Systems Group, LLC
(ESG). ESG assists schools, hospitals, governmental facilities, and other
private institutions to reduce energy and maintenance costs by upgrading their
facilities with energy-efficient equipment. ESG’s customer base is located
throughout the Midwest and Southeast United States. Prior to April 2003, ESG
was
a consolidated venture between the Company and Citizens Gas with the Company
owning two-thirds. In April 2003, the Company purchased the remaining interest
in ESG.
Miller
and Reliant Services, LLC
Effective
July 1, 2006, the Company purchased the remaining 50% ownership in Miller,
making Miller a wholly owned subsidiary. The results of Miller’s operations,
formerly accounted for using the equity method, have been included in
consolidated results since July 1, 2006. Prior to this transaction, Miller
was 100 percent owned by Reliant Services,
LLC (Reliant). Reliant provided facilities locating and meter reading
services to the Company’s utilities, as well as other utilities. Reliant exited
the meter reading and facilities locating businesses in 2006.
Other
Businesses
The
Other
Businesses group includes a variety of wholly owned operations and investments
that invest in broadband communication services, energy-related opportunities
and services, real estate, and leveraged leases, among other investments. Major
investments at December 31, 2006, include Haddington Energy Partnerships, two
partnerships both approximately 40% owned; and wholly owned subsidiaries,
Southern Indiana Properties, Inc. and Energy Realty, Inc.
The
Company had an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom). The Company also had
an
approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which
was
formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides
broadband services, such as cable television, high-speed internet, and advanced
local and long distance phone services, to the greater Evansville, Indiana
area.
The Company sold its investment in SIGECOM during 2006. See “Item 7 Management’s
Discussion and Analysis of Results of Operations and Financial Condition”
regarding the Company’s Other Businesses for additional information related to
transactions involving Utilicom.
Synthetic
Fuel
The
Company has an 8.3 percent ownership interest in Pace Carbon Synfuels, LP (Pace
Carbon). Pace Carbon produces and sells coal-based synthetic fuel using Covol
technology, and based on current US tax law, its members receive a tax credit
for every ton of coal-based synthetic fuel sold. In addition, Vectren Fuels,
Inc., a wholly owned subsidiary involved in coal mining, receives processing
fees from a synfuel producer unrelated to Pace Carbon for a portion of its
coal
production. Under current tax laws, these synfuel related credits and fees
end after 2007. See “Item 7 Management’s Discussion and Analysis of Results of
Operations and Financial Condition” regarding the Company’s Synfuel-Related
activities for additional information related to Pace Carbon and Vectren
Fuels.
Personnel
As
of
December 31, 2006, the Company and its consolidated subsidiaries had 3,348
employees, of which 1,994 are subject to collective bargaining arrangements.
Approximately 1,333 employees are employees of Miller.
During
2006, the Company, through its wholly owned subsidiary, Miller, entered into
several distributing and operating agreements with a variety of construction
unions including Laborers International Union of America, International Union
of
Operating Engineers, the Teamsters, and the United Association of Journeymen
and
Apprentices of the Plumbing and Pipe Fitting Industry. These agreements expire
at various dates in 2009 through 2011. Miller negotiates these agreements
through the Distribution and Contractors Association and the Pipeline
Contractors Association.
In
November 2005, the Company reached a four-year agreement with Local 175 of
the
Utility Workers Union of America, ending October 2009. In September 2005, the
Company reached a four-year agreement with Local 135 of the Teamsters,
Chauffeurs, Warehousemen, and Helpers Union, ending September 2009.
In
July
2004, the Company reached a three-year labor agreement with Local 702 of the
International Brotherhood of Electrical Workers, ending June 2007. In January
2004, the Company reached a five-year labor agreement, ending December 2008,
with Local 1393 of the International Brotherhood of Electrical Workers and
United Steelworkers of America Locals 12213 and 7441.
ITEM
1A. RISK FACTORS
Investors
should consider carefully the following factors that could cause the Company’s
operating results and financial condition to be materially adversely affected.
New risks may emerge at any time, and the Company cannot predict those risks
or
estimate the extent to which they may affect the Company’s businesses or
financial performance.
Vectren
is a holding company, and its assets consist primarily of investments in its
subsidiaries.
Dividends
on Vectren’s common stock depend on the earnings, financial condition, capital
requirements and cash flow of its subsidiaries, principally Utility Holdings
and
Enterprises, and the distribution or other payment of earnings from
those entities to Vectren. Should the earnings, financial condition,
capital requirements or cash flow of, or legal requirements applicable to,
them
restrict their ability to pay dividends or make other payments to the
Company, its ability to pay dividends on its common stock could be limited
and
its stock price could be adversely affected. Vectren’s results of operations,
future growth and earnings and dividend goals also will depend on the
performance of its subsidiaries. Additionally, certain of the Company’s lending
arrangements contain restrictive covenants, including the maintenance of a
total
debt to total capitalization ratio, which could limit its ability to pay
dividends.
Vectren
operates in an increasingly competitive industry, which may affect its future
earnings.
The
utility industry has been undergoing dramatic structural change for several
years, resulting in increasing competitive pressure faced by electric and gas
utility companies. Increased competition may create greater risks to the
stability of Vectren’s earnings generally and may in the future reduce its
earnings from retail electric and gas sales. Currently, several states,
including Ohio, have passed legislation that allows customers to choose their
electricity supplier in a competitive market. Indiana has not enacted such
legislation. Ohio regulation also provides for choice of commodity providers
for
all gas customers. In 2003, the Company implemented this choice for its gas
customers in Ohio. Indiana has not adopted any regulation requiring gas choice
except for large-volume customers. Vectren cannot provide any assurance that
increased competition or other changes in legislation, regulation or policies
will not have a material adverse effect on its business, financial condition
or
results of operations.
A
significant portion of Vectren’s gas and electric utility sales are space
heating and cooling. Accordingly, its operating results may fluctuate with
variability of weather.
Vectren’s
gas and electric utility sales are sensitive to variations in weather
conditions. The Company forecasts utility sales on the basis of normal weather,
which represents a long-term historical average. Since Vectren does not have
a
weather-normalization mechanism for its electric operations or its Ohio natural
gas operations, significant variations from normal weather could have a material
impact on its earnings. However, the impact of weather on the gas operations
in
the Company’s Indiana territories has been significantly mitigated through the
implementation on October 15, 2005, of a normal temperature adjustment
mechanism.
Vectren’s
gas and electric utility sales are concentrated in the
Midwest.
The
operations of the Company’s regulated utilities are concentrated in central and
southern Indiana and west central Ohio and are therefore impacted by changes
in
the Midwest economy in general and changes in particular industries concentrated
in the Midwest. These industries include automotive assembly, parts and
accessories, feed, flour and grain processing, metal castings, aluminum
products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic
products, gypsum products, electrical equipment, metal specialties, glass,
steel
finishing, pharmaceutical and nutritional products, gasoline and oil products,
and coal mining.
Risks
related to the regulation of Vectren’s businesses, including environmental
regulation, could affect the rates the Company charges its customers, its costs
and its profitability.
Vectren’s
businesses are subject to regulation by federal, state and local regulatory
authorities. In particular, Vectren is subject to regulation by the FERC,
the IURC and the PUCO. These authorities regulate many aspects of its
transmission and distribution operations, including construction and maintenance
of facilities, operations, safety and the rates that the Company can charge
customers and the rate of return that Vectren's utilities are authorized to
earn. The Company’s ability to obtain rate increases to maintain its current
authorized rate of return depends upon regulatory discretion, and there can
be
no assurance that Vectren will be able to obtain rate increases or rate
supplements or earn its current authorized rate of return.
In
addition, Vectren’s operations and properties are subject to extensive
environmental regulation pursuant to a variety of federal, state and municipal
laws and regulations. These environmental regulations impose, among other
things, restrictions, liabilities and obligations in connection with storage,
transportation, treatment and disposal of hazardous substances and waste and
in
connection with spills, releases and emissions of various substances in the
environment. Such emissions from electric generating facilities include
particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury,
among others.
Environmental
legislation also requires that facilities, sites and other properties associated
with Vectren’s operations be operated, maintained, abandoned and reclaimed to
the satisfaction of applicable regulatory authorities. The Company’s current
costs to comply with these laws and regulations are significant to its results
of operations and financial condition. In addition, claims against the Company
under environmental laws and regulations could result in material costs and
liabilities. With the trend toward stricter standards, greater regulation,
more
extensive permit requirements and an increase in the number and types of assets
operated by Vectren subject to environmental regulation, its investment in
environmentally compliant equipment, and the costs associated with operating
that equipment, have increased and are expected to increase in the future.
Further,
there are proposals to address global climate change that would regulate carbon
dioxide (CO2)
and
other greenhouse gases. Any future legislative or regulatory actions taken
to
address global climate change could adversely affect Vectren’s business and
results of operations by, for example, requiring changes in, and increased
costs
related to, the Company’s fossil fuel generating plants and coal mining
operations.
From
time to time, Vectren is subject to material litigation and regulatory
proceedings.
The
Company,
as well
as its equity investees such as ProLiance, may be subject to
material litigation and regulatory proceedings from time to time. There can
be
no assurance that the outcome of these matters will not have a material adverse
effect on Vectren’s business, results of operations or financial condition.
Vectren’s electric
operations are subject to various risks.
The
Company’s electric generating facilities are subject to operational risks that
could result in unscheduled plant outages, unanticipated operation and
maintenance expenses and increased purchased power costs. Such operational
risks
can arise from circumstances such as facility shutdowns due to equipment failure
or operator error; interruption of fuel supply or increased prices of fuel
as
contracts expire; disruptions in the delivery of electricity; inability to
comply with regulatory or permit requirements; labor disputes; and natural
disasters.
Vectren
may experience significantly increased gas costs.
Commodity
prices for natural gas purchases have increased and become more volatile in
recent years. Subject to regulatory approval, Vectren’s utility subsidiaries are
allowed recovery of gas costs from their retail customers through
commission-approved gas cost adjustment mechanisms. As a result, profit margins
on gas sales are not expected to be impacted. Nevertheless, regulators may
disallow, and have in the past disallowed, recovery of a portion of gas costs
for various reasons, including but limited to, a finding by the regulator that
natural gas was not prudently procured, as an example. In addition, it is
possible that as a result of this near term change in natural gas commodity
prices, Vectren’s subsidiaries may experience increased interest expense due to
higher working capital requirements, increased uncollectible accounts expense
and unaccounted for gas and some level of price sensitive reduction in volumes
sold or delivered. However,
the Company believes that the negative earnings impact on the reduction of
price
sensitive natural gas volumes sold is significantly mitigated by Indiana and
Ohio orders received in the fourth quarter of 2006 that authorize lost margin
recovery.
The
impact of MISO participation is uncertain.
Since
February 2002 and with the IURC’s approval, the Company has been a member
of the MISO. The MISO serves the electrical transmission needs of much of the
Midwest and maintains operational control over Vectren’s electric transmission
facilities as well as that of other Midwest utilities.
On
April
1, 2005, the MISO energy market commenced operation (the Day 2 energy market).
As a result of being a market participant, Vectren now bids its owned generation
into the Day Ahead and Real Time markets and procure power for its retail
customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
As
a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including Vectren’s electric transmission facilities, its
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the nature
of
MISO’s policies regarding use of transmission facilities, as well as ongoing
FERC initiatives and uncertainties around Day 2 energy market operations, it
is
difficult to predict near term operational impacts. However, it is believed
that
MISO’s regional operation of the transmission system will ultimately lead to
reliability improvements within the Midwestern transmission system.
The
potential need to expend capital for improvements to the transmission system,
both to Vectren’s facilities as well as to those facilities of adjacent
utilities, over the next several years will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
Wholesale
power marketing activities may add volatility to earnings.
Vectren’s
regulated electric utility engages in wholesale power marketing activities
that
primarily involve asset optimization strategies. These optimization strategies
primarily involve the offering of utility-owned or contracted generation into
the MISO hourly and real time markets. As part of these strategies, the Company
may also execute energy contracts that are integrated with portfolio
requirements around power supply and delivery. Projected earnings from wholesale
marketing activities may vary based on fluctuating prices for electricity and
the amount of electric generating capacity or purchased power available, beyond
that needed to meet firm service requirements.
If
Vectren does not accurately forecast future commodities prices or if its hedging
procedures do not operate as planned in certain nonutility businesses, the
Company’s net income could be reduced or the Company may experience
losses.
The
operations of ProLiance as well as the Company’s nonutility gas retail supply
and coal mining businesses execute forward and option contracts that
commit them to purchase and sell natural gas and coal in the future,
including forward contracts to purchase commodities to fulfill forecasted
sales
transactions that may or may not occur. If the value of these contracts changes
in a direction or manner that is not anticipated, or if the forecasted sales
transactions do not occur, Vectren may experience losses.
To
lower
the financial exposure related to commodity price fluctuations, these nonutility
businesses may execute contracts that hedge the value of commodity price risk.
As part of this strategy, Vectren may utilize fixed-price forward physical
purchase and sales contracts, and/or financial forwards, futures, swaps and
option contracts traded in the over-the-counter markets or on exchanges.
However, although almost all natural gas and coal positions are hedged, with
either these contracts or with Vectren’s owned coal inventory and known
reserves, Vectren does not hedge its entire exposure or its positions to market
price volatility. To the extent Vectren’s forecasts of future commodities prices
are inaccurate, its hedging procedures do not work as planned, its coal reserves
cannot be accessed or it has unhedged positions, fluctuating commodity prices
are likely to cause the Company’s net income to be volatile and may lower its
net income.
The
performance of Vectren’s nonutility businesses are also subject to certain
risks.
Execution
of gas
marketing strategies by ProLiance as well as the execution of the Company’s coal
mining and energy infrastructure services strategies, and the success
of efforts to invest in and develop new opportunities in the nonutility
business area is subject to a number of risks. These risks include, but are
not
limited to, the effects of weather; failure of installed performance contracting
products to operate as planned; storage field and mining property development;
increased coal mining industry regulation; potential legislation that may limit
CO2
and
other greenhouse gases emissions; creditworthiness of customers and joint
venture partners; factors associated with physical energy trading activities,
including price, basis, credit, liquidity, volatility, capacity, and interest
rate risks; changes in federal, state or local legal requirements, such as
changes in tax laws or rates; and changing market conditions.
Vectren’s
nonutility businesses support its regulated utilities pursuant to service
contracts by providing natural gas supply services, coal, and energy
infrastructure services. In most instances, Vectren’s ability to maintain these
service contracts depends upon regulatory discretion and negotiation with
interveners, and there can be no assurance that it will be able to obtain future
service contracts, or that existing arrangements will not be revisited.
Vectren’s
synfuel results would be adversely affected if synfuel credits are limited
or
disallowed.
Under
current tax laws, synfuel related tax credits and fees end after 2007. The
Permanent Subcommittee on Investigations of the U.S. Senate’s Committee on
Governmental Affairs has an ongoing investigation relating to synfuel tax
credits.
The
Internal Revenue Service has issued private letter rulings, which concluded
that
the synthetic fuel produced at the Pace Carbon facilities should qualify for
tax
credits. The IRS has completed tax audits of Pace Carbon for the years 1998
through 2001 without challenging tax credit calculations. As a partner of Pace
Carbon, Vectren has reflected synfuel tax credits in its consolidated results
from inception through December 31, 2006 of approximately $92 million, of which
approximately $81 million have been generated since 2001. To date, Vectren
has
been in a position to utilize or carryforward substantially all of the credits
generated.
Synfuel
tax credits are only available when the price of oil is less than a base price
specified by the tax code, adjusted for inflation. For 2007, Vectren has hedged
100% of expected production to help offset a phase-out due to high oil prices.
However, during the year, the hedges could cause quarterly earnings volatility
due to mark-to-market accounting. If production is not interrupted during 2007,
the average oil price will have an immaterial effect on annual earnings.
However, if oil prices increase enough to produce a substantial phase-out prior
to year-end and production is halted or Vectren chooses to “opt out”, the
proceeds on hedges and the reduction in production costs could result in
increased earnings. Also, if production is interrupted for reasons other than
oil prices and tax credits are not earned, the Company could be at risk for
the
cost of the hedges.
Vectren’s
nonutility group competes with larger, full-service energy providers, which
may
limit its ability to grow its business.
Competitors
for Vectren’s nonutility businesses include regional, national and global
companies. Many of Vectren’s competitors are well-established and have larger
and more developed networks and systems, greater name recognition, longer
operating histories and significantly greater financial, technical and marketing
resources. This competition, and the addition of any new competitors, could
negatively impact the financial performance of the nonutility group and the
Company’s ability to grow its nonutility businesses.
Catastrophic
events could adversely affect Vectren’s facilities and
operations.
Catastrophic
events such as fires, earthquakes, explosions, floods, tornados, terrorist
acts
or other similar occurrences could adversely affect Vectren’s facilities and
operations.
Workforce
risks could affect Vectren’s financial results.
The
Company is subject to various workforce risks, including but not limited to,
the
risk that it will be unable to attract and retain qualified personnel; that
it
will be unable to effectively transfer the knowledge and expertise of an aging
workforce to new personnel as those workers retire; and that it will be unable
to reach collective bargaining arrangements with the unions that represent
certain of its workers, which could result in work stoppages.
A
downgrade in Vectren’s credit ratings could negatively affect its ability to
access capital.
The
following table shows the current ratings assigned to certain outstanding debt
by Moody’s and Standard & Poor’s:
|
Current
Rating
|
||
|
Standard
|
||
|
Moody’s
|
&
Poor’s
|
|
|
Utility
Holdings, Indiana Gas and SIGECO senior unsecured debt
|
Baa1
|
A-
|
|
Utility
Holdings commercial paper program
|
P-2
|
A-2
|
The
current outlook of both Moody’s and Standard and Poor’s is stable and are
categorized as investment grade. A security rating is not a recommendation
to
buy, sell, or hold securities. The rating is subject to revision or withdrawal
at any time, and each rating should be evaluated independently of any other
rating. Standard and Poor’s and Moody’s lowest level investment grade rating is
BBB- and Baa3, respectively.
Vectren
may be required to obtain additional permanent financing (1) to fund its capital
expenditures, investments and debt security redemptions and maturities and
(2)
to further strengthen its capital structure and the capital structures of its
subsidiaries. If the rating agencies downgrade the Company’s credit ratings,
particularly below investment grade, or withdraw Vectren’s ratings, it may
significantly limit Vectren’s access to the debt capital markets and the
commercial paper market, and the Company’s borrowing costs would increase. In
addition, Vectren would likely be required to pay a higher interest rate in
future financings, and its potential pool of investors and funding sources
would
likely decrease. Finally, there is no assurance that the Company will have
access to the equity capital markets to obtain financing when necessary or
desirable.
Anti-takeover
provisions in Vectren’s certificate of Articles of Incorporation and Bylaws as
well as Vectren’s shareholders rights plan and certain provisions of the Indiana
Business Corporation Law could delay or prevent a change in control that
might
be beneficial to the interests of the Company’s stockholders.
Provisions
in Vectren’s Articles of Incorporation and Bylaws as well as Vectren’s
shareholders rights plan and certain provisions of the Indiana Business
Corporation Law (the ICBL) may make it more difficult and expensive for a
third
party to acquire control of the Company even if a change of control would
be
beneficial to the interests of its shareholders. For example, Vectren’s Articles
of Incorporation and Bylaws prohibit its shareholders from calling a special
meeting, require advance notice for proposals by shareholders and nominations,
and prevent the removal of Vectren’s directors by its shareholders other than
for cause and with the affirmative vote of the holders of at least 80% of
the
voting power of all the shares entitled to vote in the election of directors.
In
addition, the Vectren board has adopted a shareholder rights agreement designed
to deter certain takeover tactics that may discourage potential takeover
attempts. The IBCL also limits certain business combination transactions
between
Vectren and any person who acquires 10% or more of the Company’s common shares
(an "interested shareholder") without its board's approval or, in certain
cases,
the approval of holders of a majority of Vectren’s shares not owned by such
interested shareholder. The IBCL may also cause a shareholder acquiring shares
of the Company’s common stock beyond specified thresholds to lose the right to
vote those shares unless a majority of disinterested common shares approves
the
exercise of such voting rights. The foregoing may adversely affect the market
price of Vectren’s common stock by discouraging potential takeover attempts that
the Company’s stockholders may favor.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM
2. PROPERTIES
Gas
Utility Services
Indiana
Gas owns and operates four active gas storage fields located in Indiana covering
58,130 acres of land with an estimated ready delivery from storage capability
of
5.6 BCF of gas with maximum peak day delivery capabilities of 145,000 MCF per
day. Indiana Gas also owns and operates three liquefied petroleum (propane)
air-gas manufacturing plants located in Indiana with the ability to store 1.5
million gallons of propane and manufacture for delivery 33,000 MCF of
manufactured gas per day. In addition to its company owned storage and propane
capabilities, Indiana Gas has contracted for 17.8 BCF of storage with a maximum
peak day delivery capability of 299,717 MMBTU per day. Indiana Gas’ gas delivery
system includes 12,505 miles of distribution and transmission mains, all of
which are in Indiana except for pipeline facilities extending from points in
northern Kentucky to points in southern Indiana so that gas may be transported
to Indiana and sold or transported by Indiana Gas to ultimate customers in
Indiana.
SIGECO
owns and operates three underground gas storage fields located in Indiana
covering 6,070 acres of land with an estimated ready delivery from storage
capability of 6.3 BCF of gas with maximum peak day delivery capabilities of
108,000 MCF per day. In addition to its company owned storage delivery
capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak
day delivery capability of 19,166 MMBTU per day. SIGECO's gas delivery system
includes 3,166 miles of distribution and transmission mains, all of which are
located in Indiana.
The
Ohio
operations own and operate three liquefied petroleum (propane) air-gas
manufacturing plants, all of which are located in Ohio. The plants can store
.5
million gallons of propane, and the plants can manufacture for delivery 52,187
MCF of manufactured gas per day. In addition to its propane delivery
capabilities, the Ohio operations have contracted for 12.0 BCF of storage with
a
maximum peak day delivery capability of 246,080 MMBTU per day. The Ohio
operations’ gas delivery system includes 5,356 miles of distribution and
transmission mains, all of which are located in Ohio.
Electric
Utility Services
SIGECO's
installed generating capacity as of December 31, 2006, was rated at 1,301 MW.
SIGECO's coal-fired generating facilities are the Brown Station with two units
of 500 MW of combined capacity, located in Posey County approximately eight
miles east of Mt. Vernon, Indiana; the Culley Station with two
units
of 356 MW of combined capacity, and Warrick Unit 4 with 150 MW of capacity.
Both
the Culley and Warrick Stations are located in Warrick County near Yankeetown,
Indiana. SIGECO's gas-fired turbine peaking units are: two 80 MW gas turbines
(Brown Unit 3 and Brown Unit 4) located at the Brown Station; two Broadway
Avenue Gas Turbines located in Evansville, Indiana with a combined capacity
of
115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65 MW); and
two Northeast Gas Turbines located northeast of Evansville in Vanderburgh
County, Indiana with a combined capacity of 20 MW. The Brown Unit 3 and Broadway
Avenue Unit 2 turbines are also equipped to burn oil. Total capacity of SIGECO's
six gas turbines is 295 MW, and they are generally used only for reserve,
peaking, or emergency purposes due to the higher per unit cost of generation.
Pursuant to the settlement between the Company, the Department of Justice,
and
the USEPA, the Company ceased operation of Culley Unit 1, with generating
capacity of 50 MW, effective December 31, 2006 and is excluded from the total
capacity above.
SIGECO's
transmission system consists of 894 circuit miles of 138,000 and 69,000 volt
lines. The transmission system also includes 30 substations with an installed
capacity of 5,057 megavolt amperes (Mva). The electric distribution system
includes 4,199 pole miles of lower voltage overhead lines and 331 trench miles
of conduit containing 1,833 miles of underground distribution cable. The
distribution system also includes 99 distribution substations with an installed
capacity of 2,010 Mva and 52,449 distribution transformers with an installed
capacity of 2,448 Mva.
SIGECO
owns utility property outside of Indiana approximating nine miles of 138,000
volt electric transmission line which is located in Kentucky and which
interconnects with Louisville Gas and Electric Company's transmission system
at
Cloverport, Kentucky.
Nonutility
Properties
Subsidiaries
other than the utility operations have no significant properties other than
the
ownership and operation of coal mining property in Indiana. The assets of the
coal mining operations comprise approximately 4% of total assets. The assets
of
Miller comprise approximately 3% of total assets.
Property
Serving as Collateral
SIGECO's
properties are subject to the lien of the First Mortgage Indenture dated as
of
April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and
Deutsche Bank, as successor Trustee, as supplemented by various supplemental
indentures.
ITEM
3. LEGAL PROCEEDINGS
The
Company is party to various legal proceedings arising in the normal course
of
business. In the opinion of management, there are no legal proceedings pending
against the Company that are likely to have a material adverse effect on its
financial position, results of operations, or cash flows. See the notes to
the
consolidated financial statements regarding commitments and contingencies,
environmental matters, rate and regulatory matters and the settlement of a
lawsuit involving ProLiance. The consolidated financial statements are included
in “Item 8 Financial Statements and Supplementary Data.”
ITEM
4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
No
matters were submitted during the fourth quarter to a vote of security
holders.
PART
II
ITEM
5. MARKET FOR COMPANY'S
COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY
SECURITIES
Market
Data, Dividends Paid, and Holders of Record
The
Company’s common stock trades on the New York Stock Exchange under the symbol
‘‘VVC.’’ For each quarter in 2006 and 2005, the high and low sales prices for
the Company’s common stock as reported on the New York Stock Exchange and
dividends paid are presented below.
|
Cash
|
|
Common
Stock Price Range
|
|||||
|
|
|
|
Dividend
|
|
High
|
|
Low
|
|
2006
|
|||||||
|
First
Quarter
|
0.305
|
|
$
28.00
|
|
$
25.60
|
||
|
|
Second
Quarter
|
|
0.305
|
|
27.52
|
|
25.24
|
|
|
Third
Quarter
|
|
0.305
|
|
28.42
|
|
26.00
|
|
|
Fourth
Quarter
|
|
0.315
|
|
29.25
|
|
26.67
|
|
2005
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
$
0.295
|
|
$
27.95
|
|
$
25.82
|
|
|
Second
Quarter
|
|
0.295
|
|
28.98
|
|
26.01
|
|
|
Third
Quarter
|
|
0.295
|
|
29.46
|
|
26.50
|
|
|
Fourth
Quarter
|
|
0.305
|
|
28.75
|
|
25.00
|
On
January 31, 2007, the board of directors declared a dividend of $0.315 per
share, payable on March 1, 2007, to common shareholders of record on February
15, 2007.
As
of
January 31, 2007, there were 10,949 shareholders of record of the Company’s
common stock.
Quarterly
Share Purchases
Periodically,
the Company purchases shares from the open market to satisfy share requirements
associated with the Company’s share-based compensation plans. However, no such
open market purchases were made by the Company during the three months ended
December 31, 2006.
Dividend
Policy
Common
stock dividends are payable at the discretion of the board of directors, out
of
legally available funds. The Company’s policy is to distribute approximately 65%
of earnings over time. On an annual basis, this percentage has varied and will
continue to vary due to short-term earnings volatility. The Company has
increased its dividend for 47 consecutive years. While the Company is under
no
contractual obligation to do so, it intends to continue to pay dividends and
increase its annual dividend consistent with historical practice. Nevertheless,
should the Company’s financial condition, operating results, capital
requirements, or other relevant factors change, future payments of dividends,
and the amounts of these dividends, will be reassessed.
Certain
lending arrangements contain restrictive covenants, including the maintenance
of
a total debt to total capitalization ratio, which could limit the Company’s
ability to pay dividends. These restrictive covenants are not expected to affect
the Company’s ability to pay dividends in the near term.
ITEM
6. SELECTED FINANCIAL DATA
The
following selected financial data is derived from the Company’s audited
consolidated financial statements and should be read in conjunction with those
financial statements and notes thereto contained in this Form 10-K.
|
Year
Ended December 31,
|
||||||||||||||||
|
(In
millions, except per share data)
|
2006
|
2005
|
2004
|
2003
|
2002
|
|||||||||||
|
Operating
Data:
|
||||||||||||||||
|
Operating
revenues
|
$
|
2,041.6
|
$
|
2,028.0
|
$
|
1,689.8
|
$
|
1,587.7
|
$
|
1,523.8
|
||||||
|
Operating
income
|
$
|
220.5
|
$
|
213.1
|
$
|
199.5
|
$
|
196.0
|
$
|
211.3
|
||||||
|
Net
income
|
$
|
108.8
|
$
|
136.8
|
$
|
107.9
|
$
|
111.2
|
$
|
114.0
|
||||||
|
Average
common shares outstanding
|
75.7
|
75.6
|
75.6
|
70.6
|
67.6
|
|||||||||||
|
Fully
diluted common shares outstanding
|
76.2
|
76.1
|
75.9
|
70.8
|
67.9
|
|||||||||||
|
Basic
earnings per share
|
|
|
|
|
|
|||||||||||
|
on common stock
|
$
|
1.44
|
$
|
1.81
|
$
|
1.43
|
$
|
1.58
|
$
|
1.69
|
||||||
|
Diluted
earnings per share
|
|
|
|
|
|
|||||||||||
|
on common stock
|
$
|
1.43
|
$
|
1.80
|
$
|
1.42
|
$
|
1.57
|
$
|
1.68
|
||||||
|
Dividends
per share on common stock
|
$
|
1.23
|
$
|
1.19
|
$
|
1.15
|
$
|
1.11
|
$
|
1.07
|
||||||
|
|
|
|
|
|
|
|||||||||||
|
Balance
Sheet Data:
|
|
|
|
|
|
|||||||||||
|
Total
assets
|
$
|
4,091.6
|
$
|
3,868.1
|
$
|
3,586.9
|
$
|
3,353.4
|
$
|
3,136.5
|
||||||
|
Long-term
debt, net
|
$
|
1,208.0
|
$
|
1,198.0
|
$
|
1,016.6
|
$
|
1,072.8
|
$
|
954.2
|
||||||
|
Redeemable
preferred stock
|
$
|
-
|
$
|
-
|
$
|
0.1
|
$
|
0.2
|
$
|
0.3
|
||||||
|
Common
shareholders' equity
|
$
|
1,174.2
|
$
|
1,143.3
|
$
|
1,094.8
|
$
|
1,071.7
|
$
|
869.9
|
||||||
ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
The
following discussion and analysis should be read in conjunction with the
consolidated financial statements and notes thereto.
Executive
Summary of Consolidated Results of Operations
|
Year
Ended December 31,
|
||||||||
|
(In
millions, except per share data)
|
2006
|
|
2005
|
|
2004
|
|||
|
Net
income
|
|
$
108.8
|
|
$
136.8
|
|
$
107.9
|
||
|
|
Attributed
to:
|
|
|
|
|
|
|
|
|
|
|
Utility
Group
|
|
$ 91.4
|
|
$
95.1
|
|
$ 83.1
|
|
|
|
Nonutility
Group
|
|
18.1
|
|
48.2
|
|
26.4
|
|
|
|
Corporate
& Other
|
|
(0.7)
|
|
(6.5)
|
|
(1.6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share
|
|
$
1.44
|
|
$
1.81
|
|
$
1.43
|
||
|
|
Attributed
to:
|
|
|
|
|
|
|
|
|
|
|
Utility
Group
|
|
$
1.21
|
|
$
1.26
|
|
$
1.10
|
|
|
|
Nonutility
Group
|
|
0.24
|
|
0.64
|
|
0.35
|
|
|
|
Corporate
& Other
|
|
(0.01)
|
|
(0.09)
|
|
(0.02)
|
Results
For
the
year ended December 31, 2006, reported earnings were $108.8 million, or $1.44
per share, compared to $136.8 million, or $1.81 per share, in 2005 and $107.9
million, or $1.43 per share, in 2004. The decline in 2006 results compared
to
2005 is primarily attributable to the decline in synfuels results of $0.22
per
share, a $0.09 per share charge related to the settlement of a lawsuit involving
ProLiance Energy, LLC (ProLiance) and continued declines in customer usage.
Losses associated with synfuels-related activities were $0.07 per share in
2006,
compared to earnings of $0.15 per share in 2005 and earnings of $0.16 per share
in 2004. Excluding the results from synfuel-related activities, earnings in
2006
were $1.51 per share compared to $1.66 per share in 2005 and $1.27 per share
in
2004.
Utility
Group results reflect the impact of a constructive regulatory environment.
The
Company received orders in the fourth quarter of 2006 that authorize lost margin
recovery related to the Company’s Ohio customers and a majority of Indiana
natural gas customers, and an order in the fourth quarter of 2005 for a normal
temperature adjustment mechanism with respect to the Company’s Indiana natural
gas customers. The Company also utilizes rider mechanisms to recover
capital expenditures associated with compliance with Clean Air Act and Clean
Air
Mercury requirements, among other costs. In addition, the Company has
implemented base rate increases since 2003 and currently has two cases before
the IURC where orders are expected in 2007. The revenue increases, including
the
proposed increases in the two pending cases, are required to offset increased
operating and financing costs, the effect on usage from higher commodity prices,
and the impact of recent weather unfavorable compared to 30-year normal
temperatures.
Gas
utility base rate increases added revenues of approximately $4.2 million in
2006
compared to 2005, and $33.8 million in 2005 compared to 2004. Increased revenues
associated with recovery of pollution control investments were $2.6 million
in
2006 compared to 2005 and $14.3 million in 2005 compared to 2004. Increased
revenues associated with lost margin recovery were $2.0 million in 2006 compared
to 2005.
In
2006
compared to 2005, the decline in Utility Group earnings is primarily the result
of continued declines in customer usage, higher depreciation and interest costs,
and wholesale power marketing margins $6.2 million, or $3.7 million after tax,
lower than the prior year. The decline was mitigated somewhat by the
implementation of regulatory initiatives noted above, the impact of a lower
effective tax rate, and a gain realized on the sale of a storage asset.
In
2005
compared to 2004, the $0.16 per share earnings increase is largely due to
increased base rates, recovery of pollution control investments, weather, and
wholesale power marketing activities. The improved utility margins were
partially offset by higher operating and depreciation expense. The 2005 results
also reflect a $4.1 million, $2.4 million after tax, charge recorded pursuant
to
the disallowance of Ohio gas costs.
In
2006,
2005, and 2004 weather across all utilities was unfavorable compared to 30-year
normal temperatures. Management estimates the effect of weather compared to
normal was unfavorable $0.06 per share in 2006, unfavorable $0.04 per share
in
2005, and unfavorable $0.09 per share in 2004. The 2006 weather effect contains
the full impact of a normal temperature adjustment (NTA) mechanism implemented
in the Company’s Indiana natural gas service territories in the fourth quarter
of 2005.
The
Utility Group generates revenue primarily from the delivery of natural gas
and
electric service to its customers. The primary source of cash flow for the
Utility Group results from the collection of customer bills and the payment
for
goods and services procured for the delivery of gas and electric services.
The
results of the Utility Group are impacted by weather patterns in its service
territory and general economic conditions both in its Indiana and Ohio service
territories as well as nationally.
Primary
nonutility operations include Energy Marketing and Services companies, Coal
Mining operations, and Energy Infrastructure Services companies. Energy
Marketing and Services contributed earnings of $14.9 million in 2006, $29.7
million in 2005, and $13.8 million in 2004. Results in 2006 and 2004 contain
costs associated with the settlement of a lawsuit involving ProLiance. The
Company’s portion of those costs totaled $6.6 million after tax in 2006 and $1.4
million after tax in 2004. Coal Mining operations contributed earnings of $5.0
million in 2006, $5.3 million in 2005, and $0.4 million in 2004. Energy
Infrastructure Services contributed earnings of $4.6 million in 2006, $0.3
million in 2005, and $4.6 million in 2004.
In
total
and excluding the effects of the lawsuit involving ProLiance, the Company’s
primary nonutility business groups contributed earnings of $31.1 million, a
decrease of $4.2 million compared to 2005. Earnings from ProLiance, which are
included in Energy Marketing and Services’ results, decreased $6.2 million year
over year due largely to record earnings in 2005. ProLiance’s earnings in 2005
increased significantly due to larger spreads between financial and physical
markets, which resulted from market disruptions caused by Gulf Coast hurricanes.
The earnings decrease was offset by results from Energy Infrastructure Services
companies, which include Energy Systems Group and Miller Pipeline. They
contributed additional earnings of $3.4 million and $1.3 million respectively.
Earnings growth, excluding the effects of the lawsuit, in 2005 compared to
2004
totaled $15.1 million and was primarily driven by increased earnings from
ProLiance and improved coal mining operations.
Effective
July 1, 2006, the Company purchased the remaining 50% ownership in Miller
Pipeline Corporation (Miller), making Miller a wholly owned subsidiary.
Prior to this transaction, Miller was a 50% owned joint venture accounted for
using the equity method. The results of Miller’s operations have been included
in consolidated results since July 1, 2006. While the acquisition of Miller
is
not expected to have a material impact on the overall financial statements,
consolidating Miller resulted in, among other impacts, a $77.6 million increase
in Nonutility
revenues
and a
$60.8 million increase in Other
operating expense in
2006 when
compared to 2005. The transaction also increased consolidated Goodwill
by
approximately $31.0 million and intangible assets, which are included in
Other
assets,
by $14.0
million.
Results
from other nonutility businesses, which were losses of $1.1 million in 2006,
income of $1.2 million in 2005 and losses of $4.5 million in 2004, were
primarily affected by the Company’s broadband investments and its investment in
Haddington Energy Partners. In 2006, the Company sold its investment in SIGECOM,
LLC to a third party at a loss of approximately $1.3 million. The year ended
December 31, 2004 also reflects after tax charges totaling $6.0 million
associated with SIGECOM, LLC and other broadband related investments. Earnings
associated with Haddington, which sold investments in 2005 and 2004 at net
gains, totaled $0.1 million in 2006, compared to $3.9 million in 2005 and $2.0
million in 2004.
Finally,
and separate from the ongoing operations, 2006 Synfuels-related results,
inclusive of the expected phase out of tax credits, the impairment of
synfuel-related assets, the related hedging activity, the impact of insurance
contracts and processing fees, resulted in losses of $3.8 million in 2006.
Mark
to market losses associated with financial contracts hedging 2007 production
recognized in 2006 totaled $1.5 million. Earnings from Synfuels-related
activities were $11.7 million in 2005 and $12.1 million in 2004.
The
Nonutility Group
generates revenue or earnings from the provision of services to customers.
The
activities of the Nonutility Group are closely linked to the utility industry,
and the results of those operations are generally impacted by factors similar
to
those impacting the overall utility industry.
The
2005
Corporate and Other $0.09 loss per share reflects an additional contribution
to
the Vectren Foundation of $6.5 million, or $4.2 million after tax, to sustain
its giving program over the next several years. The contribution is included
in
Other
operating expenses
in the
Consolidated Statements of Income.
In
this
discussion and analysis of results of operations, the results of the Utility
Group and Nonutility Group are presented on a per share basis. Such per share
amounts are based on the earnings contribution of each group included in
Vectren’s consolidated results divided by Vectren’s average shares outstanding
during the period. The earnings per share of the groups do not represent a
direct legal interest in the assets and liabilities allocated to either group
but rather represent a direct equity interest in Vectren Corporation's assets
and liabilities as a whole.
The
Company has in place a disclosure committee that consists of senior management
as well as financial management. The committee is actively involved in the
preparation and review of the Company’s SEC filings.
Dividends
Dividends
declared for the year ended December 31, 2006, were $1.23 per share compared
to
$1.19 per share in 2005 and $1.15 per share in 2004. In October 2006, the
Company’s board of directors increased its quarterly dividend to $0.315 per
share from $0.305 per share.
Detailed
Discussion of Results of Operations
Following
is a more detailed discussion of the results of operations of the Company’s
Utility and Nonutility operations. The detailed results of operations for these
operations are presented and analyzed before the reclassification and
elimination of certain intersegment transactions necessary to consolidate those
results into the Company’s Consolidated Statements of Income. Other than the
$6.5 million contribution made in 2005 to the Vectren Foundation discussed
above, Corporate and Other operations are not significant.
Results
of Operations of the Utility Group
Utility
operations are comprised of Vectren Utility Holdings, Inc.’s operations, which
consist of the Company’s regulated operations and other operations that provide
information technology and other support services to those regulated operations.
The Company segregates its regulated operations into a Gas Utility Services
operating segment and an Electric Utility Services operating segment. The Gas
Utility Services segment provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and to west central Ohio. The Electric
Utility Services segment provides electric distribution services primarily
to
southwestern Indiana, and includes the Company’s power generating and asset
optimization operations. In total, these regulated operations supply natural
gas
and/or electricity to more than one million customers. The results of operations
of the Utility Group before certain intersegment eliminations and
reclassifications for the years ended December 31, 2006, 2005, and 2004, follow:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions, except per share data)
|
2006
|
|
2005
|
|
2004
|
|||||
|
OPERATING
REVENUES
|
||||||||||
|
Gas
utility
|
$
|
1,232.5
|
$
|
1,359.7
|
$
|
1,126.2
|
||||
|
Electric
utility
|
422.2
|
421.4
|
371.3
|
|||||||
|
Other
|
1.8
|
0.7
|
0.5
|
|||||||
|
Total
operating revenues
|
1,656.5
|
1,781.8
|
1,498.0
|
|||||||
|
OPERATING
EXPENSES
|
||||||||||
|
Cost
of gas sold
|
841.5
|
973.3
|
778.5
|
|||||||
|
Cost
of fuel & purchased power
|
151.5
|
144.1
|
116.8
|
|||||||
|
Other
operating
|
239.0
|
241.3
|
220.4
|
|||||||
|
Depreciation
& amortization
|
151.3
|
141.3
|
127.8
|
|||||||
|
Taxes
other than income taxes
|
64.2
|
65.2
|
58.2
|
|||||||
|
Total
operating expenses
|
1,447.5
|
1,565.2
|
1,301.7
|
|||||||
|
OPERATING
INCOME
|
209.0
|
216.6
|
196.3
|
|||||||
|
OTHER
INCOME
|
||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
-
|
-
|
0.2
|
|||||||
|
Other
– net
|
7.6
|
5.9
|
7.1
|
|||||||
|
Total
other income
|
7.6
|
5.9
|
7.3
|
|||||||
|
Interest
expense
|
77.5
|
69.9
|
67.4
|
|||||||
|
INCOME
BEFORE INCOME TAXES
|
139.1
|
152.6
|
136.2
|
|||||||
|
Income
taxes
|
47.7
|
57.5
|
53.1
|
|||||||
|
NET
INCOME
|
$
|
91.4
|
$
|
95.1
|
$
|
83.1
|
||||
|
BASIC
EARNINGS PER SHARE
|
$
|
1.21
|
$
|
1.26
|
$
|
1.10
|
||||
Significant
Fluctuations
Utility
Group Margin
Throughout
this discussion, the terms Gas utility margin and Electric utility margin are
used. Gas utility margin is calculated as Gas
utility revenues
less the
Cost
of gas sold.
Electric utility margin is calculated as Electric
utility revenues
less the
Cost
of fuel & purchased
power.
The
Company believes Gas utility and Electric utility margins are better indicators
of relative contribution than revenues since gas prices and fuel costs can
be
volatile and are generally collected on a dollar-for-dollar basis from
customers. These measures exclude Other
operating expenses, Depreciation and amortization, and
Taxes other than income taxes,
which
are included in the calculation of operating income.
Margin
generated from the sale of natural gas and electricity to residential and
commercial customers is seasonal and is impacted by weather patterns in the
Company’s service territories. The weather impact in the Company’s Indiana gas
utility service territories is mitigated by a normal temperature adjustment
mechanism, which was implemented in the fourth quarter of 2005. Margin generated
from sales to large customers (generally industrial, other contract, and firm
wholesale customers) is primarily impacted by overall economic conditions.
Margin is also impacted by the collection of state mandated taxes, which
fluctuate with gas costs, as well as other tracked expenses and is also impacted
by some level of price sensitivity in volumes sold or delivered. Electric
generating asset optimization activities are primarily affected by market
conditions, the level of excess generating capacity, and electric transmission
availability. Following is a discussion and analysis of margin generated from
regulated utility operations.
Gas
utility margin (Gas utility revenues less Cost of gas sold)
Gas
utility margin and throughput by customer type follows:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
2006
|
2005
|
2004
|
|||||||
|
Gas
utility revenues
|
$
|
1,232.5
|
$
|
1,359.7
|
$
|
1,126.2
|
||||
|
Cost
of gas sold
|
841.5
|
973.3
|
778.5
|
|||||||
|
Total
gas utility margin
|
$
|
391.0
|
$
|
386.4
|
$
|
347.7
|
||||
|
Margin
attributed to:
|
||||||||||
|
Residential
& commercial customers
|
$
|
330.2
|
$
|
333.2
|
$
|
297.7
|
||||
|
Industrial
customers
|
48.0
|
48.3
|
45.7
|
|||||||
|
Other
customers
|
12.8
|
4.9
|
4.3
|
|||||||
|
Sold
& transported volumes in MMDth attributed to:
|
||||||||||
|
Residential
& commercial customers
|
97.7
|
112.9
|
114.5
|
|||||||
|
Industrial
customers
|
84.9
|
87.2
|
85.8
|
|||||||
|
Total
sold & transported volumes
|
182.6
|
200.1
|
200.3
|
|||||||
Gas
utility margins were $391.0 million for the year ended December 31, 2006, an
increase of $4.6 million compared to 2005. A full year of base rate increases
implemented in the Company’s Ohio service territory which increased margin $4.2
million, a $4.1 million disallowance of Ohio gas costs in 2005, the effects
of
the normal temperature adjustment mechanism (NTA) implemented in 2005 in the
Company’s Indiana service territories, and
the
lost margin recovery authorization implemented in the fourth quarter of 2006,
more than offset the effects of warm weather, lower usage, and decreased tracked
expenses recovered dollar for dollar in margin.
For
the
year ended December 31, 2006, compared to 2005, management estimates that
weather 14 percent warmer than normal and 9 percent warmer than prior year
would
have decreased margins $13.1 million compared to the prior year, had the NTA
not
been in effect. Weather, net of the NTA, resulted in an approximate $2.0 million
year over year increase in gas utility margin. Incremental revenue associated
with the lost margin recovery totaled $2.0 million in 2006. Further, for the
year ended December 31, 2006, margin associated with tracked expenses and
revenue taxes decreased $3.4 million. The average cost per dekatherm of gas
purchased for the year ended December 31, 2006, was $8.64 compared to $9.05
in
2005 and $6.92 in 2004.
For
the
year ended December 31, 2005, gas utility margins increased $38.7 million
compared to 2004. The increase is primarily due to the favorable impact of
gas
base rate increases of $33.8 million and additional pass through expenses and
revenue taxes recovered in margins of $5.8 million compared to 2004. Results
for
the year ended December 31, 2005, reflect the disallowance of Ohio gas costs
ordered by the PUCO described above. For the year ended December 31, 2005,
weather was 5% warmer than normal but 4% colder than the prior year. Management
estimates that weather, including the effects of the normal temperature
adjustment mechanism, increased margin an estimated $2.5 million compared to
2004.
Electric
Utility Margin (Electric Utility Revenues less Cost of Fuel and Purchased
Power)
Electric
Utility margin and volumes sold by customer type follows:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
|
2006
|
|
2005
|
|
2004
|
||||
|
Electric
utility revenues
|
$
|
422.2
|
$
|
421.4
|
$
|
371.3
|
||||
|
Cost
of fuel & purchased power
|
151.5
|
144.1
|
116.8
|
|||||||
|
Total
electric utility margin
|
$
|
270.7
|
$
|
277.3
|
$
|
254.5
|
||||
|
Margin
attributed to:
|
||||||||||
|
Residential
& commercial customers
|
$
|
162.9
|
$
|
170.8
|
$
|
157.3
|
||||
|
Industrial
customers
|
70.2
|
66.9
|
63.7
|
|||||||
|
Municipal
& other customers
|
24.0
|
19.8
|
18.6
|
|||||||
|
Subtotal:
Retail & firm wholesale
|
$
|
257.1
|
$
|
257.5
|
$
|
239.6
|
||||
|
Asset
optimization
|
$
|
13.6
|
$
|
19.8
|
$
|
14.9
|
||||
|
Electric
volumes sold in GWh attributed to:
|
||||||||||
|
Residential
& commercial customers
|
2,789.7
|
2,933.2
|
2,830.9
|
|||||||
|
Industrial
customers
|
2,570.4
|
2,575.9
|
2,511.2
|
|||||||
|
Municipal
& other customers
|
644.4
|
689.9
|
645.9
|
|||||||
|
Total
retail & firm wholesale volumes sold
|
6,004.5
|
6,199.0
|
5,988.0
|
|||||||
Retail & Firm Wholesale Margin
Electric
retail and firm wholesale utility margin was $257.1 million for the year ended
December 31, 2006 and was generally flat compared to 2005. The recovery of
pollution control related investments and associated operating expenses and
related depreciation increased margins $2.6 million year over year. Higher
demand charges and other items increased industrial customer margin
approximately $3.2 million year over year. These increases were offset by
decreased residential and commercial usage. The decreased usage was due
primarily to mild weather during the peak cooling season. For 2006 compared
to
2005, the estimated decrease in margin due to unfavorable weather was $4.6
million ($4.0 million for below normal cooling weather and $0.6 million for
heating weather). During 2006, cooling degree days were 5% below normal. In
2005, cooling degree days were 9% above normal.
Electric
retail and firm wholesale utility margin increased $17.9 million in 2005
compared to 2004. The recovery of pollution control related investments and
associated operating expenses and depreciation expense increased margins $14.3
million compared to 2004. Cooling weather was 9% warmer than normal and 21%
warmer than 2004. In 2005 compared to 2004, the estimated increase in electric
margin related to weather was $4.0 million ($3.8 million related to cooling
weather and $0.2 million related to heating weather).
Margin
from Asset Optimization Activities
Periodically,
generation capacity is in excess of that needed to serve retail load and firm
wholesale customers. The Company markets this unutilized capacity to optimize
the return on its owned generation assets. These optimization strategies
primarily involve the sale of excess generation into the MISO day ahead and
real-time markets. As part of these strategies, the Company may also execute
energy contracts that are integrated with portfolio requirements around power
supply and delivery.
Asset
optimization activity is comprised of the following:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
|
2006
|
|
2005
|
|
2004
|
||||
|
Off-system
sales
|
$
|
14.2
|
$
|
15.3
|
$
|
8.7
|
||||
|
Transmission
system sales
|
3.5
|
4.5
|
4.6
|
|||||||
|
Other
|
(4.1
|
)
|
0.0
|
1.6
|
||||||
|
Total
asset optimization
|
$
|
13.6
|
$
|
19.8
|
$
|
14.9
|
||||
For
the
year ended December 31, 2006, net asset optimization margins were $13.6 million,
which represents a decrease of $6.2 million compared to 2005. The decrease
is
due to the effect lower wholesale prices have had on the Company’s optimization
portfolio and lower volumes sold off system. For the year ended December 31,
2005, net asset optimization margins increased $4.9 million as compared to
2004.
The increase in margin results primarily from the timing of available capacity
and mark to market gains.
In
2005,
the Company experienced increased availability of the generating units. The
availability of excess capacity was reduced in 2006 and 2004 by scheduled
outages of owned generation related to the installation of environmental
compliance equipment. Off-system sales totaled 889.4 GWh in 2006, compared
to
1,208.1 GWh in 2005 and 670.4 GWh in 2004.
Utility
Group Operating Expenses
Other
Operating
For
the
year ended December 31, 2006, other operating expenses decreased $2.3 million
compared to 2005. Expenses in 2006 are reduced from the inclusion of a gain
on
the sale of a storage asset of approximately $4.4 million. Excluding this
gain,
operating expenses would have increased $2.1 million compared to 2005. The
increase is primarily the result of electric generation chemical costs $1.3
million higher than the prior year. Bad debt expense in the Company’s Indiana
service territories increased $0.6 million year over year due in part to
higher
gas costs.
Other
operating expenses increased $20.9 million for the year ended December 31,
2005,
compared to 2004. Amortization of rate case expenses, expenses associated
with
the Ohio choice program and integrity management programs, and expenses
recovered through margin increased $6.5 million. Bad debt expense in the
Company’s Indiana service territories was $9.3 million in 2005, an increase of
$1.8 million compared to 2004. Compensation and benefit costs increases,
including performance and share-based compensation was $6.8 million higher
than
the prior year, reflective of the return to higher earnings in 2005 as compared
to 2004. Higher maintenance, chemical costs, and all other costs account
for
$5.8 million of the increase.
Depreciation
& Amortization
Depreciation
expense increased $10.0 million in 2006 compared to 2005 and $13.5 million
in
2005 compared to 2004. In addition to depreciation on additions to plant
in
service, the increases were primarily due to incremental depreciation expense
associated with environmental compliance equipment additions. Depreciation
expense associated with environmental compliance equipment, which is recovered
in Electric
utility margin,
totaled
$14.4 million in 2006, $12.1 million in 2005, and $6.2 million in 2004. Results
for 2004 include $1.8 million of lower depreciation due to adjustments of
Ohio
depreciation rates and amortization of Indiana regulatory assets.
Taxes
Other Than Income Taxes
Taxes
other than income taxes decreased $1.0 million for the year ended December
31,
2006, compared to 2005 and increased $7.0 million in 2005 compared to 2004.
The
fluctuations are primarily attributable to variations in the collection of
utility receipts, excise, and usage taxes. These variations resulted primarily
from volatility in revenues and gas volumes sold.
Utility
Group Other Income (Expense)
Total
other income (expense)-net increased $1.7 million in 2006 compared to 2005,
and
decreased $1.4 million in 2005 compared to 2004. The fluctuations relate
primarily to capitalized interest on utility plant additions.
Utility
Group Interest Expense
In
2006,
interest expense increased $7.6 million compared to 2005 and increased $2.5
million in 2005 compared to 2004. The increases are primarily driven by rising
interest rates and higher levels of short-term borrowings due in part to higher
working capital requirements resulting from the increased gas commodity prices.
Interest
costs in 2006 also include the full impact of permanent financing transactions
completed in the fourth quarter of 2005 in which $150 million in debt-related
proceeds were received and used to retire short-term borrowings and other
long-term debt. Results for 2006 also include a partial impact from financing
transactions completed in October 2006 in which approximately $93 million in
debt related proceeds were raised and used to retire debt outstanding with
a
higher interest rate.
Utility
Group Income Taxes
Federal
and state income taxes decreased $9.8 million in 2006 compared to 2005 and
increased $4.4 million in 2005 compared to 2004. The changes
are impacted by fluctuations in pre-tax income. Income taxes recorded in
2006 reflect a $3.1 million favorable impact for an Indiana tax law change
that
resulted in the recalculation of certain state deferred income tax liabilities.
Income taxes in 2006 also include other adjustments, including adjustments
to
reflect income taxes reported on 2005 state and federal income tax returns.
Income taxes recorded in 2005 reflect favorable adjustments to accruals
resulting from the conclusion of state tax audits and other adjustments.
Environmental
Matters
The
Company is subject to federal, state, and local regulations with respect to
environmental matters, principally air, solid waste, and water quality. Pursuant
to environmental regulations, the Company is required to obtain operating
permits for the electric generating plants that it owns or operates and
construction permits for any new plants it might propose to build. Regulations
concerning air quality establish standards with respect to both ambient air
quality and emissions from electric generating facilities, including particulate
matter, sulfur dioxide (SO2),
nitrogen oxide (NOx), and mercury. Regulations concerning water quality
establish standards relating to intake and discharge of water from electric
generating facilities, including water used for cooling purposes in electric
generating facilities. Because of the scope and complexity of these regulations,
the Company is unable to predict the ultimate effect of such regulations on
its
future operations, nor is it possible to predict what other regulations may
be
adopted in the future, including any regulations to address the climate change
issue.
Clean
Air Act
Clean
Air Interstate Rule & Clean Air Mercury Rule
In
March
of 2005 USEPA finalized two new air emission reduction regulations. The
Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring
further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2)
emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR)
is
an allowance cap and trade program requiring further reductions in mercury
emissions from coal-burning power plants. Both sets of regulations require
emission reductions in two phases. The first phase deadline for both rules
is
2010 (2009 for NOx under CAIR), and the second phase deadline for compliance
with the emission reductions required under CAIR is 2015, while the second
phase
deadline for compliance with the emission reduction requirements of CAMR is
2018. The Company is evaluating compliance options and fully expects to be
in
compliance by the required deadlines.
In
February 2006, the IURC approved a multi-emission compliance plan filed by
the
Company’s utility subsidiary, SIGECO. Once the plan is implemented, SIGECO’s
coal-fired plants will be 100% scrubbed for SO2,
90%
scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury
reduction standards. The order, as previously agreed to by the OUCC and Citizens
Action Coalition, allows SIGECO to recover an approximate 8% return on up to
$110 million in capital investments through a rider mechanism which is updated
every six months for actual costs incurred. The Company will also recover
through a rider its operating expenses, including depreciation, once the
equipment is placed into service. The order also stipulates that SIGECO study
renewable energy alternatives and include a carbon forecast in future filings
with regard to new generation and further environmental compliance plans, among
other initiatives. As of December 31, 2006, the Company has made capital
investments of approximately $62.2 million related to this environmental
requirement.
NOx
SIP Call Matter
The
Company complied with Indiana’s State Implementation Plan (SIP) of the Clean Air
Act (the Act). These steps included installation of 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 currently be the
most effective method of reducing nitrogen oxide (NOx) emissions where high
removal efficiencies are required.
The
IURC
issued orders that approved:
| · |
the
Company’s project to achieve environmental compliance by investing in
clean coal technology;
|
| · |
the
Company’s investment of $258 million in capital
costs;
|
| · |
a
mechanism whereby, prior to an electric base rate case, the Company
recovers through a rider that is updated every six months, an 8%
return on
its weighted capital costs for the project; and
|
| · |
ongoing
recovery of operating costs, including depreciation and purchased
emission
allowances, related to the clean coal technology now that facilities
are
placed into service.
|
Related
annual operating expenses, including depreciation expense, were $18.7 million
in
2006, $15.4 million in 2005, and $9.7 million in 2004.
Culley
Generating Station Litigation
During
2003, the U.S. District Court for the Southern District of Indiana entered
a
consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA
that
resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit
alleged violations of the Clean Air Act by SIGECO at its Culley Generating
Station for (1) making modifications to a generating station without obtaining
required permits, (2) making major modifications to the generating station
without installing the best available emission control technology, and (3)
failing to notify the USEPA of the modifications.
Under
the
terms of the agreement, the DOJ and USEPA agreed to drop all challenges of
past
maintenance and repair activities at the Culley Generating Station. In reaching
the agreement, SIGECO did not admit to any allegations in the government’s
complaint, and SIGECO continues to believe that it acted in accordance with
applicable regulations and conducted only routine maintenance on the units.
SIGECO entered into this agreement to further its continued commitment to
improve air quality and avoid the cost and uncertainties of litigation.
Under
the
agreement, SIGECO committed to:
| · |
either
repower Culley Unit 1 (50 MW) with natural gas and equip it with
SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31,
2006;
|
| · |
operate
the existing SCR control technology recently installed on Culley
Unit 3
(287 MW) year round at a lower emission rate than that currently
required
under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
|
| · |
enhance
the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide
emissions;
|
| · |
install
a baghouse for further particulate matter reductions at Culley Unit
3 by
June 30, 2007;
|
| · |
conduct
a Sulphuric Acid Reduction Demonstration Project as an environmental
mitigation project designed to demonstrate an advance in pollution
control
technology for the reduction of sulfate emissions; and
|
| · |
pay
a $600,000 civil penalty.
|
The
Company does not believe that implementation of the settlement will have a
material effect on its results of operations or financial condition. The
$600,000 civil penalty was expensed and paid during 2003. The Company ceased
operation of Culley Unit 1 effective December 31, 2006 and the baghouse, which
is included in the $110 million IURC order discussed above, went into service
January 1, 2007.
Manufactured
Gas Plants
In
the
past, Indiana Gas, SIGECO, 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, those that operated these facilities may
now
be required to take remedial action if certain byproducts are found above the
regulatory thresholds at these sites.
Indiana
Gas 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 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
(VRP)
and is currently conducting some level of remedial activities, including
groundwater monitoring at certain sites, where deemed appropriate, and will
continue remedial activities at the sites as appropriate and
necessary.
In
conjunction with data compiled by environmental consultants, Indiana Gas 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.
In
October 2002, SIGECO received a formal information request letter from the
IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the
results of preliminary site investigations conducted in the mid-1990’s. These
site investigations confirmed that based upon the conditions known at the time,
the sites posed no imminent and/or substantial risk to human health or the
environment.
On
October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas
plant sites in IDEM's VRP. The remaining site is currently being addressed
in
the VRP by another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has
in
place with IDEM for its manufactured gas plant sites. That renewal was approved
by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory
judgment action against its insurance carriers seeking a judgment finding its
carriers liable under the policies for coverage of further investigation and
any
necessary remediation costs that SIGECO may accrue under the VRP program. While
the total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, SIGECO has recorded costs that it reasonably
expects to incur totaling approximately $7.7 million. With respect to insurance
coverage, SIGECO has received and recorded settlements from insurance carriers
in an aggregate amount approximating the costs it expects to incur.
Environmental
matters related to Indiana Gas’ and SIGECO’s manufactured gas plants have had no
material impact on results of operations or financial condition since costs
recorded to date approximate PRP and insurance settlement recoveries. While
the
Company’s utilities have recorded all costs which they presently expect 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.
Jacobsville
Superfund Site
On
July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination
site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The USEPA
has
identified four sources of historic lead contamination. These four sources
shut
down manufacturing operations years ago. When drawing up the boundaries for
the
listing, the USEPA included a 250 acre block of properties surrounding the
Jacobsville neighborhood, including Vectren's Wagner Operations Center.
Vectren's property has not been named as a source of the lead contamination,
nor
does the USEPA's soil testing to date indicate that the Vectren property
contains lead contaminated soils. Vectren's own soil testing, completed during
the construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils. At this time, Vectren anticipates
only additional soil testing, if required by the USEPA.
Global
Climate Change
Global
climate change remains a policy issue that is regularly considered for
government regulation. If legislation requiring reductions in greenhouses gases
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel plants. Further, the
Company’s nonutility coal mining operations may be adversely
affected.
Rate
and Regulatory Matters
Gas
and
electric operations with regard to retail rates and charges, terms of service,
accounting matters, issuance of securities, and certain other operational
matters specific to its Indiana customers are regulated by the IURC. The retail
gas operations of the Ohio operations are subject to regulation by the PUCO.
All
metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and
all
metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and
GCR
clauses allow the Company to charge for changes in the cost of purchased gas.
Metered electric rates contain a fuel adjustment clause (FAC) that allows for
adjustment in charges for electric energy to reflect changes in the cost of
fuel. The net energy cost of purchased power, subject to an agreed upon
benchmark, is also recovered through regulatory proceedings.
GCA,
GCR,
and FAC procedures involve periodic filings and IURC and PUCO hearings to
establish the amount of price adjustments for a designated future period. The
procedures also provide for inclusion in later periods of any variances between
the estimated cost of gas, cost of fuel, and net energy cost of purchased power
and actual costs incurred. The Company records any under-or-over-recovery
resulting from gas and fuel adjustment clauses each month in margin. A
corresponding asset or liability is recorded until the under-or-over-recovery
is
billed or refunded to utility customers.
The
IURC
has also applied the statute authorizing GCA and FAC procedures to reduce rates
when necessary to limit net operating income to a level authorized in its last
general rate order through the application of an earnings test. For the recent
past, the earnings test has not affected the Company’s ability to recover
costs.
Ohio
and Indiana Lost Margin Recovery/Conservation Filings
In
2005,
the Company filed conservation programs and conservation adjustment trackers
in
Indiana and Ohio designed to help customers conserve energy and reduce their
annual gas bills. The programs would allow the Company to recover costs of
promoting the conservation of natural gas through conservation trackers that
work in tandem with a lost margin recovery mechanism. This mechanism is designed
to allow the Company to recover the distribution portion of its rates from
residential and commercial customers based on the level of customer revenues
established in each utility’s last general rate case.
Indiana
In
December 2006, the IURC approved a settlement agreement between the Company
and
the OUCC that provides for a 5-year energy efficiency program to be implemented.
The order allows the Company’s Indiana utilities to recover the costs of
promoting the conservation of natural gas through conservation trackers that
work in tandem with a lost margin recovery mechanism that would provide for
recovery of 85% of the difference between revenues actually collected by the
Company and the revenues approved in the Company’s most recent rate case. The
order was implemented in the North service territory in December 2006 and will
be implemented in South’s service territory after its next general rate case
(see below.) While most expenses associated with these programs are recoverable,
in the first program year, the Company is required to fund $1.5 million in
program costs without recovery. Revenues recorded in 2006 as a result of this
order related to lost margin recovery totaled $0.7 million and revenues to
fund
energy efficiency programs totaled $0.6 million.
Ohio
In
September 2006, the PUCO approved a conservation proposal that would implement
a
decoupling approach, including a related conservation program, for the company’s
Ohio operations. The PUCO decision was issued following a hearing process and
the submission of a settlement by the Company, the Ohio Consumer Counselor
(OCC)
and the Ohio Partners for Affordable Energy (OPAE). That settlement was
contested by the PUCO Staff. In the decision the PUCO addressed decoupling
by
approving a two year, $2 million total, low-income conservation program to
be
funded by the Company, as well as a sales reconciliation rider intended to
be a
recovery mechanism for the difference between the weather normalized revenues
actually collected by the company and the revenues approved by the PUCO in
the
Company’s most recent rate case. The decision produced an outcome that was
different from the settlement. Following the decision, the Company and the
OPAE
advised the PUCO that they would accept the outcome even though it differed
from
the terms of the settlement. The OCC sought rehearing of the decision, which
was
denied in December, and thereafter the OCC advised the PUCO that the OCC was
withdrawing from the settlement. At that point the OCC also initiated the
process for appealing the PUCO’s September and December decisions to the Ohio
Supreme Court. Thereafter, the Company, the OPAE and the PUCO Staff advised
the
PUCO that they accepted the terms provided in the September decision, as
affirmed by the December rehearing decision. Since that time there have been
a
number of procedural filings by the parties and presently the Company is
awaiting a further decision from the PUCO. The Company believes that the PUCO
had the necessary legal basis for its decisions and thus should confirm the
outcome provided in the September decision. The
Company began recognizing the impact of this order on October 1, 2006, and
has
recorded revenues in 2006 related to the order in the amount of $1.3
million.
Vectren
South (Southern Indiana Gas & Electric) Base Rate Filings
On
September 1, 2006, Vectren South filed petitions with the IURC to adjust its
electric and gas base rates in its South service territory. The electric
petition requests an increase of $76.7 million in base rates to
recover the nearly $120 million additional investment in electric utility
infrastructure since its last base rate increase in 1995, which is not currently
included in rates charged to customers. The increase in rates also is required
to support system growth, maintenance, reliability and recovery of costs
deferred under previous IURC orders. The gas petition seeks to increase its
gas
base (non-gas cost) rates by $10.4 million to cover the ongoing costs of
operating and maintaining its natural gas distribution and storage system.
Based
upon the timelines prescribed by the IURC at the start of these proceedings,
decisions in each case are expected to be issued in the late summer of 2007.
The
initial public hearings in both cases have been conducted. On January 30, 2007,
the OUCC filed testimony in the gas rate case proposing an increase of $5.1
million.
IGCC
Certificate of Public Convenience and Necessity
On
September 7, 2006, Vectren Energy Delivery of Indiana and Duke Energy Indiana,
Inc. filed with the IURC a joint petition for a Certificate of Public
Convenience and Necessity (CPCN) for the construction of new electric capacity.
Specifically, Vectren requested the IURC approve its construction and ownership
of up to 20% of an Integrated Gasification Combined Cycle (IGCC) project.
Vectren's CPCN filing also seeks timely recovery of its 20% portion of the
project's construction costs as well as operation and maintenance costs and
additional incentives available for the construction of clean coal technology.
Initial studies of plant design have already begun, and if the project moves
forward as currently designed, plant construction is expected to begin in 2007
and continue through 2011.
Weather
Normalization
On
October 5, 2005, the IURC approved the establishment of a normal temperature
adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The OUCC
had
previously entered into a settlement agreement with Vectren Energy Delivery
of
Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated
residential and commercial natural gas customers and should mitigate weather
risk in those customer classes during the October to April heating season.
These
Indiana customer classes represent approximately 60-65% of the Company’s total
natural gas heating load.
The
NTA
mechanism will mitigate volatility in distribution charges created by
fluctuations in weather by lowering customer bills when weather is colder than
normal and increasing customer bills when weather is warmer than normal. The
NTA
has been applied to meters read and bills rendered after October 15, 2005.
Each
subsequent monthly bill for the seven-month heating season will be adjusted
using the NTA. Resulting from this order, revenues recorded in 2006 totaled
$13.6 million while refunds of $1.6 million were made in 2005.
The
order
provides that the Company will make, on a monthly basis, a commitment of
$125,000 to a universal service fund program or other low-income assistance
program for the duration of the NTA or until a general rate case.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
Gas
Utility Base Rate Settlements in 2004 and 2005
On
June
30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas
distribution business, and on November 30, 2004, approved a $24 million base
rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the
PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution
business. The base rate change in SIGECO’s service territory was implemented on
July 1, 2004; the base rate change in Indiana Gas’ service territory was
implemented on December 1, 2004; and the base rate change in VEDO’s service
territory was implemented on April 14, 2005.
The
orders also permit SIGECO and Indiana Gas to recover the on-going costs to
comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety
Improvement Tracker provides for the recovery of incremental non-capital
dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO
and $2.5 million per year for Indiana Gas. Any costs incurred in excess of
these
annual caps are to be deferred for future recovery. VEDO’s new base rates
provide for the recovery of some level of on-going costs to comply with the
Pipeline Safety Improvement Act of 2002.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission needs
of
much of the Midwest and maintains operational control over the Company’s
electric transmission facilities as well as that of other Midwest utilities.
Pursuant to an order from the IURC received in December 2001, certain MISO
startup costs (referred to as Day 1 costs) have been deferred for future
recovery in the next general rate case, which was filed in 2006.
On
April
1, 2005, the MISO energy market commenced operation (the Day 2 energy market).
As a result of being a market participant, the Company now bids its owned
generation into the Day Ahead and Real Time markets and procures power for
its
retail customers at Locational Marginal Pricing (LMP) as determined by the
MISO
market.
On
June
1, 2005, Vectren, together with three other Indiana electric utilities, received
regulatory authority from the IURC that allows recovery of fuel related costs
and deferral of other costs associated with the Day 2 energy market. The order
allows fuel related costs to be passed through to customers in Vectren’s
existing fuel cost recovery proceedings. The other non-fuel and MISO
administrative related costs are to be deferred for recovery as part of the
next
electric general rate case proceeding, which was filed in 2006. During 2006,
the
IURC reaffirmed the definition of certain costs as fuel related; the Company
is
following those guidelines.
As
a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the nature
of
MISO’s policies regarding use of transmission facilities, as well as ongoing
FERC initiatives and uncertainties around Day 2 energy market operations, it
is
difficult to predict near term operational impacts. However, as stated above,
it
is believed that MISO’s regional operation of the transmission system will
ultimately lead to reliability improvements.
The
potential need to expend capital for improvements to the transmission system,
both to SIGECO’s facilities as well as to those facilities of adjacent
utilities, over the next several years will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
Gas
Cost Recovery (GCR) Audit Proceedings
On
June
14, 2005, the PUCO issued an order disallowing the recovery of approximately
$9.6 million of gas costs relating to the two-year audit period ended November
2002. That audit period provided the PUCO staff its initial review of the
portfolio administration arrangement between VEDO and ProLiance. The
disallowance includes approximately $1.3 million relating to pipeline refunds
and penalties and approximately $4.5 million of costs for winter delivery
services purchased by VEDO to ensure reliability over the two-year period.
The
PUCO also held that ProLiance should have credited to VEDO an additional $3.8
million more than credits actually received for the right to use VEDO’s gas
transportation capacity periodically during the periods when it was not required
for serving VEDO’s customers. The PUCO also directed VEDO to either submit its
receipt of portfolio administration services to a request for proposal process
or to in-source those functions. During 2003, the Company recorded a reserve
of
$1.1 million for this matter. An additional pretax charge of $4.1 million was
recorded in
Cost
of gas sold
in 2005.
The reserve reflects management’s assessment of the impact of the PUCO
decisions, an estimate of any current impact that decision may have on
subsequent audit periods, and an estimate of a sharing in any final disallowance
by Vectren’s partner in ProLiance.
VEDO
filed its request for rehearing on July 14, 2005, and on August 10, 2005, the
PUCO granted rehearing to further consider the $3.8 million portfolio
administration issue and all interest on the findings, but denied rehearing
on
all other aspects of the case. On October 7, 2005, the Company filed an appeal
with the Ohio Supreme Court requesting that the $4.5 million disallowance
related to the winter delivery service issue be reversed. On December 21, 2005,
the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million
disallowance related to portfolio administration to $1.98 million. The Company
has appealed the $1.98 million disallowance to the Ohio Supreme Court as well.
Briefings of all matters and oral arguments were completed in November 2006, and
the parties are awaiting the Court’s ruling.
With
respect to the most recent GCR audit covering the period of November 1, 2002
through October 31, 2005, the PUCO staff recommended a disallowance of
approximately $830,000 related solely to the retention of a reserve margin
for
the winter of 2002/2003. The Company had previously reserved for the possible
disallowance given the June 2005 PUCO order but has contested the disallowance.
The PUCO will issue a decision on that issue in 2007.
As
a
result of the June 2005 PUCO order, the Company has established an annual
bidding process for VEDO’s gas supply and portfolio administration services.
Since November 1, 2005, the Company has used a third party provider for these
services.
Results
of Operations of the Nonutility
Group
The
Nonutility Group is comprised of Vectren Enterprises’ operations. The Nonutility
Group operates in three primary business areas: Energy Marketing and Services,
Coal Mining, and Energy Infrastructure Services. Energy Marketing and Services
markets and supplies natural gas and provides energy management services. Coal
Mining mines and sells coal. Energy Infrastructure Services provides underground
construction and repair and energy performance contracting services. Enterprises
also has other businesses that invest in energy-related opportunities and
services, real estate, and leveraged leases, among other investments. In
addition, the Company has investments that generate synfuel tax credits
and
processing fees relating to the production of coal-based synthetic fuels.
Enterprises supports the Company’s regulated utilities pursuant to service
contracts by providing natural gas supply services, coal, infrastructure
services, and other services. The results of operations of the Nonutility Group
for the years ended December 31, 2006, 2005, and 2004, follow:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions, except per share amounts)
|
2006
|
|
2005
|
|
2004
|
|||||
|
NET
INCOME
|
$
|
18.1
|
$
|
48.2
|
$
|
26.4
|
||||
|
BASIC
EARNINGS PER SHARE
|
$
|
0.24
|
$
|
0.64
|
$
|
0.35
|
||||
|
NET
INCOME ATTRIBUTED TO:
|
||||||||||
|
Energy
Marketing & Services
|
$
|
14.9
|
$
|
29.7
|
$
|
16.6
|
||||
|
Mining
Operations
|
5.0
|
5.3
|
0.4
|
|||||||
|
Energy
Infrastructure Services
|
4.6
|
0.3
|
1.8
|
|||||||
|
Other
Businesses
|
(1.1
|
)
|
1.2
|
(4.5
|
)
|
|||||
|
Synfuels-related
|
(5.3
|
)
|
11.7
|
12.1
|
||||||
Energy
Marketing & Services
Energy
Marketing and Services is comprised of the Company’s gas marketing operations,
energy management services, and retail gas supply operations.
ProLiance
Energy LLC (ProLiance), a nonutility energy marketing affiliate of Vectren
and
Citizens Gas and Coke Utility (Citizens Gas), provides services to a broad
range
of municipalities, utilities, industrial operations, schools, and healthcare
institutions located throughout the Midwest and Southeast United States.
ProLiance’s customers include Vectren’s utilities and nonutility gas supply
operations and Citizens Gas. ProLiance’s primary businesses include gas
marketing, gas portfolio optimization, and other portfolio and energy management
services. Consistent with its ownership percentage, Vectren is allocated 61%
of
ProLiance’s profits and losses; however, governance and voting rights remain at
50% for each member; and therefore the Company accounts for its investment
in
ProLiance using the equity method of accounting.
Vectren
received regulatory approval on April 25, 2006, from the IURC for ProLiance
to
continue to provide natural gas supply services to the Company’s Indiana
utilities through March 2011. ProLiance has not provided gas supply/portfolio
administration services to VEDO since October 31, 2005.
Vectren
Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural
gas and other related products and services in the Midwest and Southeast United
States to customers opting for choice among energy providers.
Net
income generated by Energy Marketing and Services for the year ended December
31, 2006, was $14.9 million compared to $29.7 million in 2005 and $13.8 million
in 2004. Throughout the periods presented, ProLiance’s operations provided the
primary earnings contribution, totaling $18.3 million in 2006, compared to
$31.1
million in 2005 and $15.4 million in 2004. Results in 2006 and 2004 contain
costs associated with the settlement of a lawsuit by ProLiance. The Company’s
portion of those costs totaled $6.6 million after tax in 2006 and $1.4 million
after tax in 2004. Earnings in 2005 increased significantly due to larger
spreads between financial and physical markets, which resulted from market
disruptions caused by Gulf Coast hurricanes.
Vectren
Source operated at a loss of $0.4 million in 2006, compared to earnings of
$0.9
million in 2005 and a loss of $0.4 million in 2004. Vectren Source added
approximately 20,000 new customers during 2006, bringing its total customer
base
to 150,000. The year over year decrease in earnings is primarily due to higher
marketing costs and weather. Customer growth was the primary source of increased
earnings in 2005 compared to 2004.
ProLiance
Lawsuit Settlement
On
November 22, 2006, ProLiance agreed to settle a 2002 civil lawsuit between
the
City of Huntsville, Alabama and ProLiance. The $21.6 million settlement
(Huntsville Settlement) relates to a dispute over a contractual relationship
with Huntsville Utilities during 2000-2002.
During
2006, ProLiance recorded an $18.3 million charge recognizing the Huntsville
Settlement. During 2004, ProLiance recorded $3.9 million as a reserve for loss
contingency recognizing the initial unfavorable judgment and the uncertainties
related to ultimate outcome. During 2006 and 2005, $0.1 million and $0.5 million
of legal fees were charged against the reserve.
As
an
equity investor in ProLiance, Vectren reflected its share of these charges
which
totaled $6.6 million after tax in 2006 and $1.4 million after tax in 2004.
Vectren is currently exploring whether a portion of those charges may be
recoverable from insurance carriers.
Commodity
Prices
In
response to the effects of higher gas costs, ProLiance increased its unsecured
revolving credit facilities. Those facilities expire in June 2009. These
facilities provide for a total of $400 million in short-term credit to be
available from October 1 through March 31 and $300 million from April 1 through
September 30. These credit facilities are not guaranteed by Vectren
Corporation.
Coal
Mining
Coal
Mining Operations mine and sell coal to the Company’s utility operations and to
third parties through its wholly owned subsidiary Vectren Fuels, Inc.
(Fuels).
Coal
Mining net income for the year ended December 31, 2006, was $5.0 million in
2006, compared to $5.3 million in 2005 and $0.4 million in 2004. Mining
Operations’ 2006 earnings were generally flat compared to the prior year. Higher
revenue and tax benefits from depletion have been offset by unfavorable geologic
conditions, the rising costs of commodities used in operations, and high sulfur
content. The increased performance in 2005 compared to 2004 is primarily due
to
greater production, improved yield and higher prices, despite the effects of
rising costs for steel, explosives, and diesel fuel. The Company produced 4.0
million tons of coal in 2006, compared to 4.4 million tons of coal in 2005
and
3.6 million tons in 2004.
In
April
2006, Fuels secured the rights to open two new underground mines near Vincennes,
Indiana. The first mine is expected to be operational by early 2009, with the
second mine opening the following year. Reserves at the two mines are estimated
at 80 million tons of recoverable number-five coal at 11,200 BTU (British
thermal units) and 6-pound sulfur dioxide. Management estimates a $125 million
investment to access the reserves. Once in production, the two new mines are
expected to produce 5 million tons of coal per year.
Energy
Infrastructure Services
Energy
Infrastructure Services provides energy performance contracting operations
through Energy Systems Group, LLC (ESG) and natural gas and water
distribution, transmission, construction repair and rehabilitation as well
as
the repair and rehabilitation of gas, water, and wastewater facilities through
Miller Pipeline (Miller).
Net
income generated by Energy Infrastructure Services for the year ended December
31, 2006, was $4.6 million compared to $0.3 million in 2005 and $4.6 million
in
2004. The significant increase in earnings in 2006 compared to 2005 is due
primarily to monetizing backlog at ESG and the recent acquisition of the
remaining 50 percent ownership interest in Miller. During 2006, the Company
exited the meter reading and line locating businesses, which it had previously
provided through Reliant Services, LLC.
Energy
Infrastructure’s net income decreased $4.3 million in 2005 compared to 2004. The
2005 decrease is primarily attributable to fewer large pipeline projects and
delays in the start of an awarded wastewater project at Miller and energy
efficiency contracts at ESG. In addition, 2005 results were further affected
by
increased overhead from an acquisition completed by ESG in 2004.
Other
Businesses
The
Other
Businesses Group includes a variety of operations and investments including
investments in the Haddington Energy Partnerships (Haddington). The earnings
impact of exiting the broadband business is also included in Other
Businesses.
Other
Businesses reported a net loss of $1.1 million in 2006 compared to net income
of
$1.2 million in 2005 and a loss of $4.5 million in 2004. Results for 2006
reflect a $1.3 million loss on the sale of SIGECOM and lower earnings from
Haddington. Results for 2005 reflect $1.9 million of increased earnings from
Haddington compared to 2004. During 2004, the Company recorded charges related
to its broadband investments totaling $6.0 million after tax. Results in 2005
were further affected by planned decreases in leveraged lease income as well
as
additional charges associated with Vectren Communication Services, Inc.
Haddington
The
Haddington Energy Partnerships are equity method investments that invest in
energy-related ventures. Earnings from Haddington for the year ended December
31, 2006, were $0.1 million compared to $3.9 million in 2005 and $2.0 million
in
2004. In 2005, Haddington sold its investment in Lodi Gas Storage, LLC for
cash.
The Company recognized its portion of the gain resulting from that sale which
totaled $3.9 million after tax. During 2004, these partnerships sold their
investments in SAGO Energy, LP, for cash and wrote-down their investment in
Nations Energy Holdings, resulting in a net after tax gain of $1.8 million.
Utilicom
The
Company had an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom). The Company also had
an
approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which
was
formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides
broadband services, such as cable television, high-speed internet, and advanced
local and long distance phone services, to the greater Evansville, Indiana
area.
The Company accounted for its investments in Utilicom and Holdings using the
cost method of accounting.
Other
Utilicom-related subsidiaries also owned franchising agreements to provide
broadband services to the greater Indianapolis, Indiana and Dayton, Ohio
markets. In 2004, the build out of these markets was further evaluated, and
the
Company concluded that it was unlikely it would make additional investments
in
those markets. As a result, the Company recorded charges totaling $6.0 million,
or $3.6 million after-tax, to write off investments made in the Indianapolis
and
Dayton markets and to write down its investment in SIGECOM.
In
August
2006, SIGECOM’s majority owner and the Company sold their interests in SIGECOM
to WideOpenWest, LLC. Resulting
from the sale, the Company recorded an after tax loss of $1.3 million in
2006. Proceeds to the Company, which include the settlement of notes receivable,
are expected to total approximately $45 million. The Company anticipates
receiving the proceeds in early 2007.
Vectren
Communications Services, Inc. (VCS)
In
2004,
as part of its decision to no longer expand its broadband-related operations,
the Company ceased operations of VCS, a municipal broadband consulting business.
This decision resulted in losses of $2.4 million after tax due primarily to
inventory write-downs, cessation charges, and other costs. In 2005, the Company
incurred approximately $1.3 million in after tax charges associated with the
settlement of a lawsuit and other charges. VCS’ total loss for 2006 was $0.2
million, compared to losses of $1.5 million in 2005 and $2.6 million in
2004.
Synfuels-Related
Results
Pace
Carbon Synfuels, LP (Pace Carbon) is a Delaware limited partnership formed
to
develop, own, and operate four projects to produce and sell coal-based synthetic
fuel (synfuel) utilizing Covol technology. The Company has an 8.3 percent
interest in Pace Carbon which is accounted for using the equity method of
accounting. The Internal Revenue Code provides for manufacturers, such as
Pace Carbon, to receive a tax credit for every ton of synthetic fuel sold.
In addition, Vectren Fuels, Inc., a wholly owned subsidiary involved in coal
mining, receives processing fees from a synfuel producer unrelated to Pace
Carbon for a portion of its coal production. Under current tax laws, these
synfuel related credits and fees cease at the end of 2007.
The
Internal Revenue Service has issued private letter rulings, which concluded
that
the synthetic fuel produced at the Pace Carbon facilities should qualify for
tax
credits. The IRS has completed tax audits of Pace Carbon for the years
1998 through 2001 without challenging tax credit calculations. As a
partner in Pace Carbon, Vectren has reflected synfuel tax credits in its
consolidated results from inception through December 31, 2006 of approximately
$92 million, of which approximately $81 million have been generated since 2001.
To date, Vectren has been in a position to utilize or carryforward substantially
all of the credits generated. Primarily from the use of these credits, the
Company generated an Alternative Minimum Tax (AMT) credit carryforward of
approximately $42.1 million at December 31, 2006.
Synfuel
tax credits are only available when the price of oil is less than a base price
specified by the Internal Revenue Code, as adjusted for inflation. The
Company estimates that high oil prices caused a 35 percent phase out of synfuel
tax credits in 2006. Therefore, of the $21.5 million tax credits generated
in
2006, only $14.0 million are reflected as a reduction to the Company’s income
tax expense.
In
July
2006, the Company suspended its participation in the production of synthetic
fuel due to the high price of oil and uncertainty of federal legislation that
might favorably affect the reference price of oil governing the phase out of
synfuel tax credits. Consistent with that decision to suspend
participation, the Company impaired its investment in Pace Carbon and expensed
funding requirements estimated at that time. Charges approximating $9.5
million, or $5.7 million after tax, were recorded in Other-net
in the
second quarter of 2006. The Company resumed participation in October 2006 as
oil
prices began to fall.
For
the
year ended December 31, 2006, synfuel-related activity, inclusive of the phase
out of tax credits, the impairment of synfuel-related assets, the related
hedging activity, and estimated impact of insurance contracts, resulted in
an
after tax loss of $3.8 million, or $0.05 per share. Mark-to-market losses
associated with financial contracts hedging 2007 production recognized in 2006
totaled $1.5 million after tax, or $0.02 per share. The
accounting for the contracts hedging 2007 production could result in some
earnings volatility throughout 2007. In 2005 and 2004,
synfuel-related earnings totaled $11.7 million and $12.1 million, respectively.
Impact
of Recently Issued Accounting Guidance
SFAS
No. 158
On
December 31, 2006,
and
after
calculating the balance sheet impact of the Company’s retirement plans using the
accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted
SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and
132(R)” (SFAS 158). SFAS 158 requires the Company to recognize the funded
status of its pension plans and postretirement plans. SFAS 158 defines the
funded status of a defined benefit plan as its assets less its projected benefit
obligation, which includes projected salary increases, and defines the funded
status of a postretirement plan as its assets less its accumulated
postretirement benefit obligation. To the extent this obligation exceeded
amounts previously recognized, the Company recorded a Regulatory
Asset
for that
portion related to its cost-based and rate regulated utilities. To the extent
that excess liability did not relate to a cost-based rate-regulated utility,
the
offset was recorded as a reduction to equity in Accumulated
Other Comprehensive Income.
As a
result of adopting this standard, the Company’s assets increased $30.0 million,
its liabilities increased $22.0 million and its equity increased $8.0
million.
SFAS
158
also requires an employer to measure the funded status of a plan as of the
date
of its year-end balance sheet and requires disclosure in the notes to the
financial statements of certain additional information related to net periodic
benefit cost for the next fiscal year. The measurement date provisions are
not
required to be adopted until 2008.
SFAS
No. 157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
157). SFAS 157 defines fair value, establishes a framework for measuring fair
value in generally accepted accounting principles (GAAP), and expands
disclosures about fair value measurements. This statement does not require
any
new fair value measurements; however, the standard will impact how other fair
value based GAAP is applied. SFAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007, and interim periods
within those fiscal years with early adoption encouraged. The
Company is currently assessing the impact this statement will have on its
financial statements and results of operations.
FIN
48
In
June
2006, the FASB issued FASB Interpretation No. 48 (FIN 48) “Accounting for
Uncertainty in Income Taxes” an interpretation of SFAS 109, Accounting for
Income Taxes. FIN 48 prescribes a recognition threshold and measurement
attribute for financial statement recognition and measurement of tax positions
taken or expected to be taken in an income tax return. FIN 48 also provides
guidance related to reversal of tax positions, balance sheet classification,
interest and penalties, interim period accounting, disclosure and transition.
The interpretation is effective for fiscal years beginning after December 15,
2006. The adoption of this standard is not expected to have a material impact
on
operating results or financial condition.
Critical
Accounting Policies
Management
is required to make judgments, assumptions, and estimates that affect the
amounts reported in the consolidated financial statements and the related
disclosures that conform to accounting principles generally accepted in the
United States. Note 2 to the consolidated financial statements describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Certain estimates used in the financial
statements are subjective and use variables that require judgment. These include
the estimates to perform goodwill and other asset impairments tests and to
determine pension and postretirement benefit obligations. The Company makes
other estimates, in the course of accounting for unbilled revenue and the
effects of regulation that are critical to the Company’s financial results but
that are less likely to be impacted by near term changes. Other estimates that
significantly affect the Company’s results, but are not necessarily critical to
operations, include depreciating utility and non-utility plant, valuing
reclamation liabilities, valuing derivative contracts, and estimating
uncollectible accounts, among others. Actual results could differ from these
estimates.
Impairment
Review of Investments
The
Company has investments in notes receivable, entities accounted for using the
cost method of accounting, and entities accounted for using the equity method
of
accounting. When events occur that may cause one of these investments to be
impaired, the Company performs an impairment analysis. An impairment analysis
of
notes receivable usually involves the comparison of the investment’s estimated
free cash flows to the stated terms of the note, or for notes that are
collateral dependent, a comparison of the collateral’s fair value to the
carrying amount of the note. An impairment analysis of cost method and equity
method investments involves comparison of the investment’s estimated fair value
to its carrying amount. Fair value is estimated using market comparisons,
appraisals, and/or discounted cash flow analyses. Calculating free cash flows
and fair value using the above methods is subjective and requires judgment
concerning growth assumptions, longevity of cash flows, and discount rates
(for
fair value calculations). In 2006 and 2004, the Company recorded after tax
impairment charges of $7.0 million and $3.6 million, respectively. These charges
primarily related to synfuel fuel-related investments and broadband investments
as more fully described below.
On
July
18, 2006, the Company opted out of its current participation in the production
of synthetic fuel due to the high price of oil and the uncertainty of federal
legislation that would favorably impact the reference price of oil governing
the
phase out of synfuel tax credits. Consistent with the Company’s decision to
cease its participation in synfuel production activities, the Company completely
impaired its $2.9 million investment in Pace Carbon. Further, the Company is
obligated to fund Pace Carbon on an installment basis for working capital and
as
tax credits are earned. The Company estimated this remaining funding obligation
and other costs to be $6.6 million and recorded that amount and the impairment
charge related to its investment, all totaling $9.5 million, or $5.7 million
after tax, in earnings in the second quarter of 2006.
During
2004, the Company performed an impairment analysis on its Utilicom-related
investments. The Company used free cash flow analyses to estimate fair value
for
the cost method portion of the Utilicom investment and recoverability of the
related notes receivable. An impairment charge totaling $6.0 million, $3.6
million after tax, was recorded as a result of the analysis. The Company sold
these investments in 2006, recording an additional loss at disposition of
approximately $1.3 million after tax.
Goodwill
Pursuant
to SFAS No. 142, the Company performs an annual impairment analysis of its
goodwill, most of which resides in the Gas Utility Services operating segment,
at the beginning of each year, and more frequently if events or circumstances
indicate that an impairment loss may have been incurred. Impairment tests are
performed at the reporting unit level. The Company has determined its Gas
Utility Services operating segment as identified in Note 16 to the
consolidated financial statements to be the reporting unit. Nonutility Group
reporting units are generally defined as the operating companies that aggregate
that operating segment. An impairment test performed in accordance with SFAS
142
requires that a reporting unit’s fair value be estimated. The Company used a
discounted cash flow model to estimate the fair value of its Gas Utility
Services operating segment, and that estimated fair value was compared to its
carrying amount, including goodwill. The estimated fair value was in excess
of
the carrying amount in 2006, 2005, and 2004 and therefore resulted in no
impairment. Goodwill related to the Nonutility Group was generally tested during
the year using market comparable data or a discounted cash flow
model.
Estimating
fair value using a discounted cash flow model is subjective and requires
significant judgment in applying a discount rate, growth assumptions, company
expense allocations, and longevity of cash flows. A 100 basis point increase
in
the discount rate utilized to calculate the Gas Utility Services segment’s fair
value also would have resulted in no impairment charge.
Pension
and Other Postretirement Obligations
The
Company estimates the expected return on plan assets, discount rate, rate of
compensation increase, and future health care costs, among other inputs, and
relies on actuarial estimates to assess the future potential liability and
funding requirements of the Company's pension and postretirement plans. The
Company annually measures its obligations on September 30. The Company used
the
following weighted average assumptions to develop 2006 periodic benefit cost:
a
discount rate of 5.50 percent, an expected return on plan assets of 8.25
percent, a rate of compensation increase of 3.25 percent, and an inflation
assumption of 3.50 percent. During 2006, the Company increased the discount
rate
by 35 basis points to value 2006 ending pension and postretirement obligations
and 2007 benefit cost due to an increase in benchmark interest rates. Future
changes in health care costs, work force demographics, interest rates, or plan
changes could significantly affect the estimated cost of these future
benefits.
Management
estimates that a 50 basis point decrease in the discount rate would have
increased 2006 periodic benefit cost by approximately $1.3 million.
Unbilled
Revenues
To
more
closely match revenues and expenses, the Company records revenues for all gas
and electricity delivered to customers but not billed at the end of the
accounting period. The Company uses actual units billed during the month to
allocate unbilled units by customer class. Those allocated units are multiplied
by rates in effect during the month to calculate unbilled revenue at balance
sheet dates. While certain estimates are used in the calculation of unbilled
revenue, the method from which these estimates are derived is not subject to
near-term changes.
Regulation
At
each
reporting date, the Company reviews current regulatory trends in the markets
in
which it operates. This review involves judgment and is critical in assessing
the recoverability of regulatory assets as well as the ability to continue
to
account for its activities based on the criteria set forth in SFAS No. 71
“Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Based on
the Company’s current review, it believes its regulatory assets are probable of
recovery. If all or part of the Company's operations cease to meet the criteria
of SFAS 71, a write off of related regulatory assets and liabilities could
be
required. In addition, the Company would be required to determine any impairment
to the carrying value of its utility plant and other regulated assets. In the
unlikely event of a change in the current regulatory environment, such
write-offs and impairment charges could be significant.
Financial
Condition
Within
Vectren’s consolidated group, Utility Holdings funds the short-term and
long-term financing needs of the Utility Group operations, and Vectren Capital
Corp (Vectren Capital) funds short-term and long-term financing needs of the
Nonutility Group and corporate operations. Vectren Corporation guarantees
Vectren Capital’s debt, but does not guarantee Utility Holdings debt. Vectren
Capital’s long-term and short-term obligations outstanding at December 31, 2006,
totaled $200.0 million and $194.7 million, respectively. Utility Holdings
outstanding long-term and short-term borrowing arrangements are jointly and
severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings
long-term and short-term obligations outstanding at December 31, 2006, totaled
$700.0 million and $270.1 million, respectively. Additionally, prior to Utility
Holdings formation, Indiana Gas and SIGECO funded their operations separately,
and therefore, have long-term debt outstanding funded solely by their
operations.
The
Company’s common stock dividends are primarily funded by utility operations.
Nonutility operations have demonstrated historical profitability, and the
ability to generate cash flows. These cash flows are primarily reinvested in
other nonutility ventures, but are also used to fund a portion of the Company’s
dividends, and from time to time may be reinvested in utility operations or
used
for corporate expenses.
The
credit ratings on outstanding senior unsecured debt of Utility Holdings and
Indiana Gas, at December 31, 2006, are A-/Baa1 as rated by Standard and Poor's
Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s),
respectively. SIGECO's credit ratings on outstanding secured debt are A/A3.
Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current
outlook of both Moody’s and Standard and Poor’s is stable. A security rating is
not a recommendation to buy, sell, or hold securities. The rating is subject
to
revision or withdrawal at any time, and each rating should be evaluated
independently of any other rating. Standard and Poor’s and Moody’s lowest level
investment grade rating is BBB- and Baa3, respectively.
The
Company’s consolidated equity capitalization objective is 45-55% of long-term
capitalization. This objective may have varied, and will vary, depending on
particular business opportunities, capital spending requirements, execution
of
long-term financing plans and seasonal factors that affect the Company’s
operations. The Company’s equity component was 48% of long-term capitalization
at both December 31, 2006, and 2005, respectively. Long-term capitalization
includes long-term debt, including current maturities and debt subject to
tender, as well as common shareholders’ equity.
The
Company expects a significant portion of its capital expenditures, investments,
and debt security redemptions to be provided by internally generated funds.
However, due to increased levels of forecasted capital expenditures and expected
growth in nonutility operations, the Company will likely require additional
permanent financing. As
of
December 31, 2006, the Company was in compliance with all financial
covenants.
Sources
& Uses of Liquidity
Operating
Cash Flow
The
Company's primary historical source of liquidity to fund working capital
requirements has been cash generated from operations, which totaled $310.2
million in 2006, compared to $268.4 million in 2005 and $238.0 million in 2004.
The $41.8 million increase in cash flow in 2006 compared to 2005 is primarily
attributable to earnings before noncash charges increasing $34.4 million year
over year. Operating cash flows in 2006 also include a $10.4 million special
dividend from ProLiance.
Cash
flow
from operating activities increased $30.4 million in 2005 compared to 2004.
Distributions from equity method investments, which principally consists of
dividends from ProLiance, decreased $3.5 million in 2005 compared to 2004.
Cash
utilized for working capital increases was $6.6 million in 2005 compared to
$31.2 million in 2004, and is the primary reason for the increased operating
cash flow. Earnings before non-cash charges were impacted by $15.5 million
and
$31.9 million in alternative minimum taxes in 2005 and 2004,
respectively.
Financing
Cash Flow
Although
working capital requirements are generally funded by cash flow from operations,
the Company uses short-term borrowings to supplement working capital needs
when
accounts receivable balances are at their highest and gas storage is refilled.
Additionally, short-term borrowings are required for capital projects and
investments until they are financed on a long-term basis.
Cash
flow
required for financing activities reflects the impact of long-term financing
arrangements executed in 2006 and 2005 and increases in common stock dividends
over the periods presented. In 2006, Utility Holdings issued $100 million of
senior unsecured securities and used those proceeds to retire higher coupon
long-term debt. In 2005, Utility Holdings issued $150 million of senior
unsecured securities and used those proceeds to retire higher coupon long-term
debt and refinance certain capital projects originally financed with short-term
borrowings. In addition, Vectren Capital issued $125 million in senior unsecured
securities and used those proceeds to fund $38 million of maturing debt and
refinance certain capital projects originally financed with short-term
borrowings. These transactions are more fully described below.
Utility
Holdings 2006
Debt Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95% senior unsecured
notes due October 1, 2036 (2036 Notes). The 30-year notes were priced at par.
The 2036 Notes are guaranteed by Utility Holdings’ three public utilities:
SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional
and
joint and several. These
notes, as well as the timely payment of principal and interest, are insured
by a
financial guarunty insurance policy by Financial Guaranty Insurance Company
(FGIC).
The
2036
Notes have no sinking fund requirements, and interest payments are due
quarterly. The notes may be called by Utility Holdings, in whole or in part,
at
any time on or after October 1, 2011, at 100% of principal amount plus accrued
interest. During the first and second quarters of 2006, Utility Holdings entered
into several interest rate hedges with a $100 million notional amount. Upon
issuance of the notes, these instruments were settled resulting in the payment
of approximately $3.3 million, which was recorded as a Regulatory
asset
pursuant
to existing regulatory orders. The value paid is being amortized as an increase
to interest expense over the life of the issue maturing October
2036.
The
net
proceeds from the sale of the 2036 Notes and settlement of the hedging
arrangements totaled approximately $92.8 million. These proceeds were used
to
repay most of the $100 million outstanding balance of Utility Holdings’ 7.25%
Senior Notes originally due October 15, 2031. These notes were redeemed on
October 19, 2006 at par plus accrued interest.
Utility
Holdings 2005
Debt Issuance
In
November 2005, Utility Holdings issued senior unsecured notes with an aggregate
principal amount of $150 million in two $75 million tranches. The first tranche
was 10-year notes due December 2015, with an interest rate of 5.45% priced
at
99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year
notes due December 2035 with an interest rate of 6.10% priced at 99.779% to
yield 6.11% to maturity (2035 Notes).
The
notes
are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas,
and VEDO. These guarantees are full and unconditional and joint and several.
The
notes have no sinking fund requirements, and interest payments are due
semi-annually. The notes may be called by Utility Holdings, in whole or in
part,
at any time for an amount equal to accrued and unpaid interest, plus the greater
of 100% of the principal amount or the sum of the present values of the
remaining scheduled payments of principal and interest, discounted to the
redemption date on a semi-annual basis at the Treasury Rate, as defined in
the
indenture, plus 20 basis points for the 2015 Notes and 25 basis points for
the
2035 Notes.
In
January and June 2005, Utility Holdings entered into forward starting interest
rate swaps with a notional value of $75 million. Upon issuance of the debt,
the
interest rate swaps were settled resulting in the receipt of approximately
$1.9
million in cash, which was recorded as a regulatory
liability
pursuant
to existing regulatory orders. The value received is being amortized as a
reduction of interest expense over the life of the issue maturing December
2035.
The
net
proceeds from the sale of the senior notes and settlement of related hedging
arrangements approximated $150 million and were used to repay short-term
borrowings and to retire approximately $50 million of long-term debt with higher
interest rates.
Vectren
Capital Corp. 2005 Debt Issuance
On
October 11, 2005, Vectren and Vectren Capital, entered into a private placement
Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various
institutional investors purchased the following tranches of notes from Vectren
Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010,
(ii)
$25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75
million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed
Senior Notes are unconditionally guaranteed by Vectren. The proceeds from this
financing were received on December 15, 2005. This Note Purchase Agreement
contains customary representations, warranties and covenants, including a
covenant to the effect that the ratio of consolidated total debt to consolidated
total capitalization will not exceed 75%.
On
October 11, 2005, Vectren and Vectren Capital entered into First Amendments
with
respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant
to
which Vectren Capital issued to institutional investors the following tranches
of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83%
Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and
(iv)
a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren
Capital issued to an institutional investor a $35 million 7.43% Senior Note
due
2012. The First Amendments (i) conform the covenants to those contained in
the
2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which
would have afforded noteholders the option to require prepayment if the ratings
of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the
unconditional guarantee by Vectren of the notes for the more limited support
agreement previously in place and (iv) provide for a 100 basis point increase
in
interest rates if the ratio of consolidated total debt to total capitalization
exceeds 65%.
Long-Term
Debt Put & Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised
on
various dates before maturity. The put or call provisions are not triggered
by
specific events, but are based upon dates stated in the note agreements, such
as
when notes are remarketed. During 2006 and 2005, no debt was put to the Company.
In 2004, debt totaling $2.5 million was put to the Company. Debt that may be
put
to the Company within one year is classified as Long-term
debt subject to tender
in
current liabilities.
Utility
Holdings, SIGECO and Indiana Gas Debt Calls
In
2006,
the Company called at par $100.0 million of Utility Holdings senior unsecured
notes originally due in 2031. In 2005, the Company called at par $49.9 million
of Indiana Gas insured quarterly senior unsecured notes originally due in
2030,
and in 2004, called at par $20.0 million of Indiana Gas insured quarterly
senior
unsecured notes originally due in 2015. The notes called in 2006, 2005 and
2004
had stated interest rates of 7.25%, 7.45% and 7.15%, respectively.
Other
Financing Transactions
At
December 31, 2005, $53.7 million of SIGECO notes could be put to the Company
in
March of 2006, the date of their next remarketing. In March of 2006, the notes
were successfully remarketed, and are now classified in Long-term
debt. Prior
to
the remarketing, the notes had tax-exempt interest rates ranging from 4.75%
to
5.00%. After the remarketing, interest rates are reset every seven days using
an
auction process.
During
2004, the Company remarketed two first mortgage bonds outstanding at SIGECO.
The
remarketing effort converted $32.8 million of outstanding fixed rate debt into
variable rate debt where interest rates reset every seven days using an auction
process. One bond, due in 2023, had a principal amount of $22.8 million and
an
interest rate of 6%. The other bond, due in 2015, had a principal amount of
$10.0 million and an interest rate of 4.3%. These remarketing efforts resulted
in the extinguishment and reissuance of debt at generally the same par value.
As
part
of the integration of Miller into the Company’s consolidated financing model,
$24.0 million of Miller’s outstanding long-term debt was retired in the fourth
quarter of 2006.
Other
debt totaling $38.0 million in 2005 and $15.0 million in 2004 was retired as
scheduled.
Investing
Cash Flow
Cash
flow
required for investing activities was $337.4 million in 2006, $239.6 million
in
2005, and $262.0 million in 2004. Capital expenditures are the primary component
of investing activities. Capital expenditures were $281.4 million in 2006
compared to $231.6 million in 2005 and $252.5 million in 2004. The years ended
December 31, 2006 and 2004 included higher levels of expenditures for
environmental compliance equipment. Other investments in 2006 were principally
impacted by the acquisition of Miller and advance royalty payments for future
coal mine development.
Available
Sources of Liquidity
At
December 31, 2006, the Company has $794.0 million of short-term borrowing
capacity, including $520.0 million for the Utility Group and $274.0 million
for
the wholly owned Nonutility Group and corporate operations, of which
approximately $250.0 million is available for the Utility Group operations
and
approximately $79.0 million is available for the wholly owned Nonutility Group
and corporate operations.
During
the fourth quarter of 2005, in response to higher natural gas prices, Utility
Holdings increased its available consolidated short-term borrowing capacity
to
$520 million, a $165 million increase over previous levels. In addition, Utility
Holdings extended the maturity of its largest credit facility, which totals
$515
million, through November 2010. Vectren Capital also extended the maturity
of
its largest facility, which totals $255 million, through November 2010. The
amendments were completed on November 10, 2005.
The
Company may periodically issue new common shares to satisfy dividend
reinvestment plan, stock option plan and other employee benefit plan
requirements. New issuances added additional liquidity of $4.5 million in
2004.
Potential
& Future Uses of Liquidity
Pension
and Postretirement Funding Obligations
The
Company believes making contributions to its qualified pension plans in the
coming years will be necessary. Management currently estimates that the
qualified pension plans will require minimum Company contributions of
approximately $8 million in 2007 and approximately $10 million in 2008. During
2006, $8.3 million in contributions were made.
Planned
Capital Expenditures & Investments
Planned
capital expenditures and investments in nonutility unconsolidated affiliates,
including contractual purchase and investment commitments discussed below,
for
the five-year period 2007 - 2011 are estimated as follows:
|
(In
millions)
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|||||||
|
Utility
Group
|
$
|
297.4
|
$
|
323.6
|
$
|
351.8
|
$
|
281.7
|
$
|
222.7
|
||||||
|
Nonutility
Group
|
74.7
|
108.8
|
72.8
|
26.1
|
31.5
|
|||||||||||
|
Total
capital expenditures & investments
|
$
|
372.1
|
$
|
432.4
|
$
|
424.6
|
$
|
307.8
|
$
|
254.2
|
||||||
Contractual
Obligations
The
following is a summary of contractual obligations at December 31,
2006:
|
(In
millions)
|
Total
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|||||||||
|
Long-term
debt (1)
|
$
|
1,256.3
|
$
|
24.0
|
$
|
-
|
$
|
-
|
$
|
47.5
|
$
|
250.0
|
$
|
934.8
|
||||||||
|
Short-term
debt
|
464.8
|
464.8
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||
|
Long-term
debt interest commitments
|
986.7
|
75.3
|
73.4
|
73.4
|
73.4
|
69.0
|
622.2
|
|||||||||||||||
|
Firm
commodity purchase commitments
|
124.3
|
96.7
|
21.4
|
3.3
|
2.9
|
-
|
-
|
|||||||||||||||
|
Plant
purchase commitments (2)
|
392.4
|
66.4
|
113.0
|
115.0
|
70.0
|
28.0
|
-
|
|||||||||||||||
|
Operating
leases
|
18.3
|
7.7
|
4.6
|
2.6
|
1.5
|
0.9
|
1.0
|
|||||||||||||||
|
Total
|
$
|
3,242.8
|
$
|
734.9
|
$
|
212.4
|
$
|
194.3
|
$
|
195.3
|
$
|
347.9
|
$
|
1,558.0
|
||||||||
| (1) |
Certain
long-term debt issues contain put and call provisions that can be
exercised on various dates before maturity. These provisions allow
holders
to put debt back to the Company at face value or the Company to call
debt
at face value or at a premium. Long-term debt subject to tender during
the
years following 2006 (in millions) is $20.0 in 2007, zero in 2008,
$80.0
in 2009, $10.0 in 2010, $30.0 in 2011 and zero
thereafter.
|
| (2) |
The
settlement period of these utility & nonutility plant obligations is
estimated.
|
The
Company’s regulated utilities have both firm and non-firm commitments to
purchase commodities as well as certain transportation and storage rights.
Costs
arising from these commitments, while significant, are pass-through costs,
generally collected dollar-for-dollar from retail customers through regulator
approved cost recovery mechanisms. Because of the pass through nature of these
costs and their insignificant impact to earnings, they have not been included
in
the listing of contractual obligations.
Off
Balance Sheet Arrangements
Guarantees
and Letters of Credit
In
the
normal course of business, Vectren issues guarantees to third parties on behalf
of its consolidated subsidiaries and unconsolidated affiliates. Such guarantees
allow those subsidiaries and affiliates to execute transactions on more
favorable terms than the subsidiary or affiliate could obtain without such
a
guarantee. Guarantees may include posted letters of credit, leasing guarantees,
and performance guarantees. As of December 31, 2006, guarantees issued and
outstanding on behalf of unconsolidated affiliates approximated $3.0 million.
The Company has accrued no liabilities for these guarantees as they relate
to
guarantees issued among related parties, or such guarantees were executed prior
to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others.”
In
2006,
the Company issued a guarantee with an approximate $5.0 million maximum risk
related to the residual value of an operating lease that expires in 2011. As
of
December 31, 2006, Vectren Corporation has a liability representing the fair
value of that guarantee of approximately $0.1 million. Liabilities accrued
for,
and activity related to, product warranties are not significant. Through
December 31, 2006, the Company has not been called upon to satisfy any
obligations pursuant to its guarantees.
Ratings
Triggers
None
of
Vectren’s currently outstanding debt arrangements contain ratings
triggers.
Forward-Looking
Information
A
“safe harbor” for forward-looking statements is provided by the Private
Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act
of
1995 was adopted to encourage such forward-looking statements without the threat
of litigation, provided those statements are identified as forward-looking
and
are accompanied by meaningful cautionary statements identifying important
factors that could cause the actual results to differ materially from those
projected in the statement. Certain matters described in Management’s Discussion
and Analysis of Results of Operations and Financial Condition are
forward-looking statements. Such statements are based on management’s beliefs,
as well as assumptions made by and information currently available to
management. When used in this filing, the words “believe”, “anticipate”,
“endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”
and similar expressions are intended to identify forward-looking statements.
In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company’s actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the
following:
| · |
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.
|
| · |
Increased
competition in the energy environment including effects of industry
restructuring and unbundling.
|
| · |
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.
|
| · |
Financial,
regulatory or accounting principles or policies imposed by the Financial
Accounting Standards Board; the Securities and Exchange Commission;
the
Federal Energy Regulatory Commission; state public utility commissions;
state entities which regulate electric and natural gas transmission
and
distribution, natural gas gathering and processing, electric power
supply;
and similar entities with regulatory
oversight.
|
| · |
Economic
conditions including the effects of an economic downturn, inflation
rates,
commodity prices, and monetary fluctuations.
|
| · |
Increased
natural gas commodity prices and the potential impact on customer
consumption, uncollectible accounts expense, unaccounted for gas
and
interest expense.
|
| · |
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.
|
| · |
The
performance of projects undertaken by the Company’s nonutility businesses
and the success of efforts to invest in and develop new opportunities,
including but not limited to, the realization of synfuel income tax
credits and the Company’s coal mining, gas marketing, and energy
infrastructure strategies.
|
| · |
Direct
or indirect effects on the Company’s business, financial condition,
liquidity and results of operations resulting from changes in credit
ratings, changes in interest rates, and/or changes in market perceptions
of the utility industry and other energy-related
industries.
|
| · |
Employee
or contractor workforce factors including changes in key executives,
collective bargaining agreements with union employees, aging workforce
issues, or work stoppages.
|
| · |
Legal
and regulatory delays and other obstacles associated with mergers,
acquisitions and investments in joint
ventures.
|
| · |
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.
|
| · |
Changes
in federal, state or local legislative 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
7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The
Company is exposed to various business risks associated with commodity prices,
interest rates, and counter-party credit. These financial exposures are
monitored and managed by the Company as an integral part of its overall risk
management program. The Company’s risk management program includes, among other
things, the use of derivatives. The Company also executes derivative contracts
in the normal course of operations while buying and selling commodities to
be
used in operations and optimizing its generation assets.
The
Company has in place a risk management committee that consists of senior
management as well as financial and operational management. The committee is
actively involved in identifying risks as well as reviewing and authorizing
risk
mitigation strategies.
Commodity
Price Risk
Regulated
Operations
The
Company’s regulated operations have limited exposure to commodity price risk for
purchases and sales of natural gas and electricity for retail customers due
to
current Indiana and Ohio regulations, which subject to compliance with those
regulations, allow for recovery of the cost of such purchases through natural
gas and fuel cost adjustment mechanisms. Nevertheless, it is possible regulators
may disallow recovery of a portion of gas costs for various reasons, including
but not limited to, a finding by the regulator that natural gas was not
prudently procured, as an example. Although Vectren’s regulated operations are
exposed to limited commodity price risk, volatile natural gas prices can
result
in higher working capital requirements, increased expenses including
unrecoverable interest costs, uncollectible accounts expense, and unaccounted
for gas, and some level of price- sensitive reduction in volumes sold or
delivered. The Company mitigates these risks by executing derivative contracts
that manage the price of forecasted natural gas purchases. These contracts
are
subject to regulation which allows for reasonable and prudent hedging costs
to
be recovered through rates. Constructive regulatory orders, such as the Indiana
and Ohio orders authorizing lost margin recovery, also mitigate these risks.
When regulation is involved, SFAS 71 controls when the offset to mark-to-market
accounting is recognized in earnings.
Commodity
prices for natural gas purchases have remained above historical levels and
continue to be more volatile. Despite
hedging strategies, this near term change in natural gas commodity prices
may
have significant effects on operating results as described above.
Wholesale
Power Marketing
The
Company’s wholesale power marketing activities include asset optimization
strategies that manage the utilization of available electric generating
capacity. These optimization strategies involve the sale of excess generation
into the MISO day ahead and real-time markets. As part of these strategies,
the
Company may also execute energy contracts that commit the Company to purchase
and sell electricity in the future. Commodity price risk results from forward
positions that commit the Company to deliver electricity. The Company mitigates
price risk exposure with planned unutilized generation capability and offsetting
forward purchase contracts. The Company accounts for asset optimization
contracts that are derivatives at fair value with the offset marked to market
through earnings.
Market
risk resulting from commodity contracts is measured by management using the
potential impact on pre-tax earnings caused by the effect a 10% adverse change
in forward commodity prices might have on market sensitive derivative positions
outstanding on specific dates. For the year ended December 31, 2005, a 10%
adverse change in forward commodity prices would have decreased earnings
by $0.3
million based upon open positions existing on the last day of that year.
No such
derivative contracts were outstanding on December 31, 2006.
Synfuel-Related
Activities
Synfuel
tax credits are only available when the price of oil is less than a base
price
specified by the Internal Revenue Code, as adjusted for inflation.
The
Company has executed derivative instruments designed to limit the effects
of a
phase out of synfuel tax credits. If
2007
average oil prices are less than $63 per barrel, these derivatives, which
as of
December 31, 2006, have a fair value of $11.2 million, would expire without
generating any value to the Company; however, no synfuel tax credits would
likely be phased out. At $64 per barrel, these derivatives are expected to
be
worth approximately $2.8 million, and for every dollar increase in the price
of
oil up to $79, these derivatives are expected to increase in value approximately
$2.8 million. At $79 per barrel or greater, these derivatives would reach
a
value in excess of $40 million; however, all synfuel tax credits would likely
be
phased out.
-43-
Other
Operations
Other
commodity-related operations are exposed to commodity price risk associated
with
fluctuating commodity prices including electricity, natural gas, and coal.
Other
commodity-related operations include regulated sales of electricity to certain
municipalities and large industrial customers and nonutility retail gas
marketing, and coal mining operations. Open positions in terms of price,
volume, and specified delivery points may occur and are managed using methods
described below with frequent management reporting.
The
Company purchases and sales commodities, including electricity, natural gas,
and
coal to meet customer demands and operational needs. The Company executes
forward and option contracts that commit the Company to purchase and sell
commodities in the future. Price risk from forward positions obligating the
Company to deliver commodities is mitigated using stored inventory, generating
capability, and offsetting forward purchase contracts. Price risk also results
from forward contracts obligating the Company to purchase commodities to
fulfill
forecasted nonregulated sales of natural gas and coal that may or may not
occur.
With the exception of a small portion of contracts that are derivatives that
qualify as hedges of forecasted transactions under SFAS 133, these contracts
are
expected to be settled by physical receipt or delivery of the
commodity.
Unconsolidated
Affiliate
ProLiance,
a nonregulated energy marketing affiliate, engages in energy hedging activities
to manage pricing decisions, minimize the risk of price volatility, and minimize
price risk exposure in the energy markets. ProLiance's market exposure arises
from storage inventory, imbalances, and fixed-price forward purchase and sale
contracts, which are entered into to support its operating activities.
Currently, ProLiance buys and sells physical commodities and utilizes financial
instruments to hedge its market exposure. However, net open positions in terms
of price, volume and specified delivery point do occur. ProLiance manages open
positions with policies which limit its exposure to market risk and require
reporting potential financial exposure to its management and its members.
Interest
Rate Risk
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The Company
manages this risk by allowing 20% and 30% of its total debt to be exposed to
variable rate volatility. However, there are times when this targeted range
of
interest rate exposure may not be attained. To manage this exposure, the Company
may use derivative financial instruments. At December 31, 2006, debt subject
to
short-term interest rate volatility and seasonal increases in short-term debt
outstanding, represented 32% of the Company's total debt portfolio.
Market
risk is estimated as the potential impact resulting from fluctuations in
interest rates on adjustable rate borrowing arrangements exposed to short-term
interest rate volatility. During 2006 and 2005, the weighted average combined
borrowings under these arrangements were $342.2 million and $390.8 million,
respectively. At December 31, 2006, and 2005, combined borrowings under these
arrangements were $550.9 million and $349.8 million, respectively. Based upon
average borrowing rates under these facilities during the years ended December
31, 2006 and 2005, an increase of 100 basis points (one percentage point) in
the
rates would have increased interest expense by $3.4 million and $3.9 million,
respectively.
Other
Risks
By
using
forward purchase contracts and derivative financial instruments to manage risk,
the Company as well as ProLiance exposes itself to counter-party credit risk
and
market risk. The Company manages 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. Market risk is the adverse effect on the value of a
financial instrument that results from a change in commodity prices or interest
rates. The Company attempts to manage exposure to market risk associated with
commodity contracts and interest rates by establishing parameters and monitoring
those 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 or refunds
cash deposits based on that review. Credit risk associated with certain
investments is also managed by a review of creditworthiness and receipt of
collateral.
ITEM
8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S
RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Vectren
Corporation’s management is responsible for establishing and maintaining
adequate internal controls over financial reporting. Those control procedures
underlie the preparation of the consolidated balance sheets, statements of
income, cash flows, and common shareholders’ equity, and related footnotes
contained herein.
These
consolidated financial statements were prepared in conformity with accounting
principles generally accepted in the United States and follow accounting
policies and principles applicable to regulated public utilities. The integrity
and objectivity of these consolidated financial statements, including required
estimates and judgments, is the responsibility of management.
These
consolidated financial statements are also subject to an evaluation of internal
control over financial reporting conducted under the supervision and with the
participation of management, including the Chief Executive Officer and Chief
Financial Officer. Based on that evaluation, conducted under the framework
in
Internal
Control — Integrated Framework issued
by
the Committee of Sponsoring Organizations of the Treadway Commission, the
Company concluded that its internal control over financial reporting was
effective as of December 31, 2006. Management certified this fact in its
Sarbanes Oxley Section 302 certifications, which are attached as exhibits to
this 2006 Form 10-K.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the
Board of Directors and Shareholders of Vectren Corporation:
We
have
audited the accompanying consolidated balance sheets of Vectren Corporation
and
subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related
consolidated statements of income, common shareholders’ equity and cash flows
for each of the three years in the period ended December 31, 2006. Our audits
also included the financial statement schedule listed in the Index at Item
15.
We also have audited management’s assessment, included in the accompanying
Management’s Report on Internal Control over Financial Reporting, included at
Item 9A, that the Company maintained effective internal control over financial
reporting as of December 31, 2006, based on criteria established in Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission. The
Company’s management is responsible for these financial statements and financial
statement schedule, for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control
over
financial reporting. Our responsibility is to express an opinion on these
financial statements and financial statement schedule, an opinion on
management’s assessment, and an opinion on the effectiveness of the Company’s
internal control over financial reporting based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal
control over financial reporting was maintained in all material respects. Our
audits of financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and
evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing
and evaluating the design and operating effectiveness of internal control,
and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our
opinions.
A
company’s internal control over financial reporting is a process designed by, or
under the supervision of, the company’s principal executive and principal
financial officers, or persons performing similar functions, and effected by
the
company’s board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain
to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors
of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented
or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In
our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of December
31, 2006 and 2005, and the results of their operations and their cash flows
for
each of the three years in the period ended December 31, 2006, in conformity
with accounting principles generally accepted in the United States of America.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein.
Also, in our opinion, management’s assessment that the Company maintained
effective internal control over financial reporting as of December 31, 2006,
is
fairly stated, in all material respects, based on the criteria established
in
Internal
Control—Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2006,
based on the criteria established in Internal Control—Integrated
Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
As
discussed in Note 7 to the consolidated financial statements, effective December
31, 2006 the Company adopted the provisions of Statement of Financial Accounting
Standards No. 158, (Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans).
DELOITTE
& TOUCHE LLP
Indianapolis,
Indiana
February
16, 2007
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
At
December 31,
|
|||||||
|
2006
|
2005
|
||||||
|
ASSETS
|
|||||||
|
Current
Assets
|
|||||||
|
Cash
& cash equivalents
|
$
|
32.8
|
$
|
20.4
|
|||
|
Accounts
receivable - less reserves of $3.1 &
|
|||||||
|
$2.8,
respectively
|
198.6
|
197.8
|
|||||
|
Accrued
unbilled revenues
|
146.5
|
240.6
|
|||||
|
Inventories
|
163.5
|
144.6
|
|||||
|
Recoverable
fuel & natural gas costs
|
1.8
|
15.4
|
|||||
|
Prepayments
& other current assets
|
172.7
|
106.4
|
|||||
|
Total
current assets
|
715.9
|
725.2
|
|||||
|
Utility
Plant
|
|||||||
|
Original cost
|
3,820.2
|
3,632.0
|
|||||
|
Less: accumulated depreciation & amortization
|
1,434.7
|
1,380.1
|
|||||
|
Net
utility plant
|
2,385.5
|
2,251.9
|
|||||
|
Investments
in unconsolidated affiliates
|
181.0
|
214.7
|
|||||
|
Other
investments
|
74.5
|
111.6
|
|||||
|
Nonutility
property - net
|
294.4
|
240.3
|
|||||
|
Goodwill
- net
|
237.8
|
207.1
|
|||||
|
Regulatory
assets
|
163.5
|
89.9
|
|||||
|
Other
assets
|
39.0
|
27.4
|
|||||
|
TOTAL
ASSETS
|
$
|
4,091.6
|
$
|
3,868.1
|
|||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
At
December 31,
|
|||||||
|
2006
|
2005
|
||||||
|
LIABILITIES
& SHAREHOLDERS' EQUITY
|
|||||||
|
Current
Liabilities
|
|||||||
|
Accounts
payable
|
$
|
180.0
|
$
|
159.0
|
|||
|
Accounts
payable to affiliated companies
|
89.9
|
162.3
|
|||||
|
Refundable
fuel & natural gas costs
|
35.3
|
7.6
|
|||||
|
Accrued
liabilities
|
147.2
|
156.6
|
|||||
|
Short-term
borrowings
|
464.8
|
299.9
|
|||||
|
Current
maturities of long-term debt
|
24.2
|
0.4
|
|||||
|
Long-term
debt subject to tender
|
20.0
|
53.7
|
|||||
|
Total
current liabilities
|
961.4
|
839.5
|
|||||
|
Long-term
Debt - Net of Current Maturities &
|
|||||||
|
Debt
Subject to Tender
|
1,208.0
|
1,198.0
|
|||||
|
Deferred
Income Taxes & Other Liabilities
|
|||||||
|
Deferred
income taxes
|
260.7
|
227.3
|
|||||
|
Regulatory
liabilities
|
291.1
|
272.9
|
|||||
|
Deferred
credits & other liabilities
|
195.8
|
186.7
|
|||||
|
Total
deferred credits & other liabilities
|
747.6
|
686.9
|
|||||
|
Minority
Interest in Subsidiary
|
0.4
|
0.4
|
|||||
|
Commitments
& Contingencies (Notes 3, 12-14)
|
|||||||
|
Common
Shareholders' Equity
|
|||||||
|
Common
stock (no par value) – issued & outstanding
|
|||||||
|
76.1
and 76.0, respectively
|
525.5
|
528.1
|
|||||
|
Retained
earnings
|
643.6
|
628.8
|
|||||
|
Accumulated
other comprehensive loss
|
5.1
|
(13.6
|
)
|
||||
|
Total
common shareholders' equity
|
1,174.2
|
1,143.3
|
|||||
|
TOTAL
LIABILITIES & SHAREHOLDERS' EQUITY
|
$
|
4,091.6
|
$
|
3,868.1
|
|||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF INCOME
(In
millions, except per share amounts)
|
Year
Ended December 31,
|
||||||||||
|
2006
|
|
2005
|
|
2004
|
||||||
|
OPERATING
REVENUES
|
||||||||||
|
Gas
utility
|
$
|
1,232.5
|
$
|
1,359.7
|
$
|
1,126.2
|
||||
|
Electric
utility
|
422.2
|
421.4
|
371.3
|
|||||||
|
Energy
services & other
|
386.9
|
246.9
|
192.3
|
|||||||
|
Total
operating revenues
|
2,041.6
|
2,028.0
|
1,689.8
|
|||||||
|
OPERATING
EXPENSES
|
||||||||||
|
Cost
of gas sold
|
841.5
|
973.3
|
778.5
|
|||||||
|
Cost
of fuel & purchased power
|
151.5
|
144.1
|
116.8
|
|||||||
|
Cost
of energy services & other
|
248.7
|
191.0
|
143.5
|
|||||||
|
Other
operating
|
341.8
|
282.2
|
252.0
|
|||||||
|
Depreciation
& amortization
|
172.3
|
158.2
|
140.1
|
|||||||
|
Taxes
other than income taxes
|
65.3
|
66.1
|
59.4
|
|||||||
|
Total
operating expenses
|
1,821.1
|
1,814.9
|
1,490.3
|
|||||||
|
OPERATING
INCOME
|
220.5
|
213.1
|
199.5
|
|||||||
|
OTHER
INCOME
|
||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
17.0
|
45.6
|
20.6
|
|||||||
|
Other
– net
|
(2.7
|
)
|
6.2
|
4.6
|
||||||
|
Total
other income
|
14.3
|
51.8
|
25.2
|
|||||||
|
Interest
expense
|
95.6
|
83.9
|
77.7
|
|||||||
|
INCOME
BEFORE INCOME TAXES
|
139.2
|
181.0
|
147.0
|
|||||||
|
Income
taxes
|
30.3
|
44.1
|
39.0
|
|||||||
|
Minority
interest
|
0.1
|
0.1
|
0.1
|
|||||||
|
NET
INCOME
|
$
|
108.8
|
$
|
136.8
|
$
|
107.9
|
||||
|
AVERAGE
COMMON SHARES OUTSTANDING
|
75.7
|
75.6
|
75.6
|
|||||||
|
DILUTED
COMMON SHARES OUTSTANDING
|
76.2
|
76.1
|
75.9
|
|||||||
|
EARNINGS
PER SHARE OF COMMON STOCK:
|
||||||||||
|
BASIC
|
$
|
1.44
|
$
|
1.81
|
$
|
1.43
|
||||
|
DILUTED
|
$
|
1.43
|
$
|
1.80
|
$
|
1.42
|
||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
Year
Ended December 31,
|
||||||||||
|
2006
|
|
2005
|
|
2004
|
||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
||||||||||
|
Net
income
|
$
|
108.8
|
$
|
136.8
|
$
|
107.9
|
||||
|
Adjustments
to reconcile net income to cash from operating activities:
|
||||||||||
|
Depreciation
& amortization
|
172.3
|
158.2
|
140.1
|
|||||||
|
Deferred
income taxes & investment tax credits
|
1.4
|
(8.6
|
)
|
5.9
|
||||||
|
Equity
in earnings of unconsolidated affiliates
|
(17.0
|
)
|
(45.6
|
)
|
(20.6
|
)
|
||||
|
Provision
for uncollectible accounts
|
15.3
|
15.1
|
11.9
|
|||||||
|
Expense
portion of pension & postretirement benefit cost
|
10.7
|
10.7
|
11.8
|
|||||||
|
Other
non-cash charges - net
|
11.4
|
1.9
|
8.3
|
|||||||
|
Changes
in working capital accounts:
|
||||||||||
|
Accounts
receivable & accrued unbilled revenue
|
108.9
|
(102.9
|
)
|
(84.0
|
)
|
|||||
|
Inventories
|
(17.6
|
)
|
(71.9
|
)
|
0.4
|
|||||
|
Recoverable/refundable
fuel & natural gas costs
|
41.3
|
3.5
|
8.9
|
|||||||
|
Prepayments
& other current assets
|
(21.2
|
)
|
36.1
|
(10.2
|
)
|
|||||
|
Accounts
payable, including to affiliated companies
|
(71.6
|
)
|
101.2
|
42.5
|
||||||
|
Accrued
liabilities
|
(23.2
|
)
|
27.4
|
11.2
|
||||||
|
Unconsolidated
affiliate dividends
|
35.8
|
18.8
|
22.3
|
|||||||
|
Changes
in noncurrent assets
|
(25.8
|
)
|
(6.9
|
)
|
(3.5
|
)
|
||||
|
Changes
in noncurrent liabilities
|
(19.3
|
)
|
(5.4
|
)
|
(14.9
|
)
|
||||
|
Net
cash flows from operating activities
|
310.2
|
268.4
|
238.0
|
|||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
||||||||||
|
Proceeds
from:
|
||||||||||
|
Long-term
debt - net of issuance costs
|
92.8
|
274.2
|
32.4
|
|||||||
|
Stock
option exercises & other stock plans
|
-
|
-
|
4.5
|
|||||||
|
Requirements
for:
|
||||||||||
|
Dividends
on common stock
|
(93.1
|
)
|
(90.5
|
)
|
(87.3
|
)
|
||||
|
Retirement
of long-term debt
|
(124.4
|
)
|
(88.5
|
)
|
(70.7
|
)
|
||||
|
Redemption
of preferred stock of subsidiary
|
-
|
(0.1
|
)
|
(0.1
|
)
|
|||||
|
Net
change in short-term borrowings
|
164.9
|
(112.5
|
)
|
139.5
|
||||||
|
Other
activity
|
(0.6
|
)
|
(0.6
|
)
|
-
|
|||||
|
Net
cash flows from financing activities
|
39.6
|
(18.0
|
)
|
18.3
|
||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
||||||||||
|
Proceeds
from:
|
||||||||||
|
Unconsolidated
affiliate distributions
|
2.0
|
6.9
|
3.2
|
|||||||
|
Other
collections
|
3.4
|
4.3
|
9.3
|
|||||||
|
Requirements
for:
|
||||||||||
|
Capital
expenditures, excluding AFUDC equity
|
(281.4
|
)
|
(231.6
|
)
|
(252.5
|
)
|
||||
|
Unconsolidated
affiliate investments
|
(16.7
|
)
|
(19.2
|
)
|
(18.2
|
)
|
||||
|
Other
investments
|
(44.7
|
)
|
-
|
(3.8
|
)
|
|||||
|
Net
cash flows from investing activities
|
(337.4
|
)
|
(239.6
|
)
|
(262.0
|
)
|
||||
|
Net
increase (decrease) in cash & cash equivalents
|
12.4
|
10.8
|
(5.7
|
)
|
||||||
|
Cash
& cash equivalents at beginning of period
|
20.4
|
9.6
|
15.3
|
|||||||
|
Cash
& cash equivalents at end of period
|
$
|
32.8
|
$
|
20.4
|
$
|
9.6
|
||||
|
Cash
paid during the year for:
|
||||||||||
|
Interest
|
$
|
92.9
|
$
|
79.6
|
$
|
75.3
|
||||
|
Income
taxes
|
36.3
|
48.1
|
26.6
|
|||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED
STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In
millions, except per share amounts)
|
Common
Stock
|
Accumulated
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|||||
|
|
|
|
|
|
|
Retained
|
|
Comprehensive
|
|
|
|
|||||
|
|
|
Shares
|
|
Amount
|
|
Earnings
|
|
Income
(Loss)
|
|
Total
|
||||||
|
Balance
at January 1, 2004
|
75.6
|
$
|
520.4
|
$
|
562.4
|
$
|
(11.1
|
)
|
$
|
1,071.7
|
||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
107.9
|
107.9
|
||||||||||||||
|
Minimum
pension liability adjustments &
|
||||||||||||||||
|
other
- net of tax
|
(0.1
|
)
|
(0.1
|
)
|
||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||
|
affiliates
- net of $2.6 in tax
|
(3.8
|
)
|
(3.8
|
)
|
||||||||||||
|
Total
comprehensive income
|
104.0
|
|||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Stock
option exercises & other stock plans
|
0.2
|
4.5
|
4.5
|
|||||||||||||
|
Dividends
($1.15 per share)
|
(87.3
|
)
|
(87.3
|
)
|
||||||||||||
|
Other
|
0.1
|
1.9
|
1.9
|
|||||||||||||
|
Balance
at December 31, 2004
|
75.9
|
526.8
|
583.0
|
(15.0
|
)
|
1,094.8
|
||||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
136.8
|
136.8
|
||||||||||||||
|
Minimum
pension liability adjustments &
|
||||||||||||||||
|
other
- net of $0.1 in tax
|
0.2
|
0.2
|
||||||||||||||
|
Cash
flow hedges
|
||||||||||||||||
|
unrealized
gains(losses) - net of $2.9 in tax
|
4.2
|
4.2
|
||||||||||||||
|
reclassifications
to net income- net of $0.2 in tax
|
(0.2
|
)
|
(0.2 | ) | ||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||
|
affiliates
- net of $1.8 in tax
|
(2.8
|
)
|
(2.8
|
)
|
||||||||||||
|
Total
comprehensive income
|
138.4
|
|||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Dividends
($1.19 per share)
|
(90.5
|
)
|
(90.5
|
)
|
||||||||||||
|
Other
|
0.1
|
1.3
|
(0.5
|
)
|
0.8
|
|||||||||||
|
Balance
at December 31, 2005
|
76.0
|
528.1
|
628.8
|
(13.6
|
)
|
1,143.3
|
||||||||||
|
Comprehensive
income:
|
||||||||||||||||
|
Net
income
|
108.8
|
108.8
|
||||||||||||||
|
Minimum
pension liability adjustments &
|
||||||||||||||||
|
other
- net of $5.4 in tax
|
7.9
|
7.9
|
||||||||||||||
|
Cash
flow hedge
|
||||||||||||||||
|
unrealized
gains(losses) - net of $1.7 in tax
|
(2.6
|
)
|
(2.6
|
)
|
||||||||||||
|
reclassifications
to net income- net of $0.7 in tax
|
(1.0
|
)
|
(1.0
|
)
|
||||||||||||
|
Comprehensive
income of unconsolidated
|
||||||||||||||||
|
affiliates
- net of $4.3 in tax
|
6.4
|
6.4
|
||||||||||||||
|
Total
comprehensive income
|
119.5
|
|||||||||||||||
|
Adoption
of SFAS 158 - net of $5.2 in tax
|
8.0
|
8.0
|
||||||||||||||
|
Common
stock:
|
||||||||||||||||
|
Dividends
($1.23 per share)
|
(93.1
|
)
|
(93.1
|
)
|
||||||||||||
|
Adoption
of SFAS 123R
|
(4.1
|
)
|
(4.1
|
)
|
||||||||||||
|
Other
|
0.1
|
1.5
|
(0.9
|
)
|
0.6
|
|||||||||||
|
Balance
at December 31, 2006
|
76.1
|
$
|
525.5
|
$
|
643.6
|
$
|
5.1
|
$
|
1,174.2
|
|||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
VECTREN
CORPORATION AND SUBSIDIARY COMPANIES
NOTES
TO THE CONSOLIDATED FINANCIAL STATEMENTS
| 1. |
Organization
and Nature of Operations
|
Vectren
Corporation (the Company or Vectren), an Indiana corporation, is an energy
holding company headquartered in Evansville, Indiana. The Company’s wholly owned
subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the
intermediate holding company for three operating public utilities: Indiana
Gas
Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO),
and the Ohio operations. Utility Holdings also has other assets that provide
information technology and other services to the three utilities. Utility
Holdings’ consolidated operations are collectively referred to as the Utility
Group. Both Vectren and Utility Holdings were exempt from registration pursuant
to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935,
which was repealed effective February 8, 2006 by the Energy Policy Act of 2005
(Energy Act). Both Vectren and Utility Holdings are holding companies as defined
by the Energy Act.
Indiana
Gas provides energy delivery services to approximately 565,000 natural gas
customers located in central and southern Indiana. SIGECO provides energy
delivery services to approximately 141,000 electric customers and approximately
112,000 gas customers located near Evansville in southwestern Indiana. SIGECO
also owns and operates electric generation to serve its electric customers
and
optimizes those assets in the wholesale power market. Indiana Gas and SIGECO
generally do business as Vectren Energy Delivery of Indiana. The Ohio operations
provide energy delivery services to approximately 318,000 natural gas customers
located near Dayton in west central Ohio. The Ohio operations are owned as
a
tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly
owned subsidiary of Utility Holdings (53% ownership), and Indiana Gas (47%
ownership). The Ohio operations generally do business as Vectren Energy Delivery
of Ohio.
The
Company, through Vectren Enterprises, Inc. (Enterprises), is also involved
in
nonutility activities in three primary business areas: Energy Marketing and
Services, Coal Mining and Energy Infrastructure Services. Energy Marketing
and
Services markets and supplies natural gas and provides energy management
services. Coal Mining mines and sells coal. Energy Infrastructure Services
provides underground construction and repair and energy performance contracting
services. Enterprises also has other businesses that invest in energy-related
opportunities and services, real estate, and leveraged leases, among other
investments. In addition, the Company has investments that generate synfuel
tax credits and
processing fees relating to the production of coal-based
synthetic fuels. These operations are collectively referred to as the
Nonutility Group.
Enterprises supports the Company’s regulated utilities pursuant to service
contracts by providing natural gas supply services, coal, infrastructure
services, and other services.
| 2. |
Summary
of Significant Accounting
Policies
|
| A. |
Principles
of Consolidation
|
The
consolidated financial statements include the accounts of the Company and its
wholly owned and majority owned subsidiaries, after elimination of significant
intercompany transactions.
The
Company has investments in partnership-like structures that are variable
interest entities as defined by FASB Interpretation 46(R), “Consolidation of
Variable Interest Entities” as a limited partner or as a subordinated lender.
The activities of these entities are to purchase or construct as well as operate
multifamily housing and office properties. The Company’s exposure to loss is
limited to its investment which as of December 31, 2006, and 2005, totaled
$13.4
million and $15.1 million, respectively, of Investments
in unconsolidated affiliates,
and
$11.5 million and $13.4 million, respectively, of Other
investments. The
Company is also the equity owner in three leveraged leases where its exposure
to
loss is limited to its net investment, which as of December 31, 2006, and 2005,
totaled $10.2 million and $7.8 million, respectively. The Company does not
consolidate any of these entities.
| B. |
Cash
& Cash Equivalents
|
All
highly liquid investments with an original maturity of three months or less
at
the date of purchase are considered cash equivalents.
| C. |
Inventories
|
Inventories
consist
of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Gas
in storage – at average cost
|
$
|
73.0
|
$
|
73.3
|
|||
|
Materials
& supplies
|
29.5
|
30.2
|
|||||
|
Fuel
(coal & oil) for electric generation
|
31.2
|
19.4
|
|||||
|
Gas
in storage – at LIFO cost
|
26.5
|
18.8
|
|||||
|
Other
|
3.3
|
2.9
|
|||||
|
Total
inventories
|
$
|
163.5
|
$
|
144.6
|
|||
Based
on
the average cost of gas purchased during December, the cost of replacing gas
in
storage carried at LIFO cost exceeded LIFO cost at December 31, 2006, and 2005,
by approximately $79.0 million and $117.0 million, respectively. Gas in storage
of the Indiana regulated operations is stated at LIFO. All other inventories
are
carried at average cost.
| D. |
Utility
Plant & Depreciation
|
Utility
plant
is
stated at historical cost, including AFUDC. Depreciation rates are established
through regulatory proceedings and are applied to all in-service utility plant.
The original cost of utility plant, together with depreciation rates expressed
as a percentage of original cost, follows:
|
At
December 31,
|
|||||||||||||
|
(In
millions)
|
2006
|
|
|
|
2005
|
|
|||||||
|
Original
Cost
|
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|
Original
Cost
|
|
Depreciation
Rates
as a
Percent
of
Original
Cost
|
|||||||
|
Gas
utility plant
|
$
|
1,956.1
|
3.6
|
%
|
$
|
1,879.1
|
3.5
|
%
|
|||||
|
Electric
utility plant
|
1,685.5
|
3.7
|
%
|
1,611.4
|
3.7
|
%
|
|||||||
|
Common
utility plant
|
45.2
|
2.6
|
%
|
44.2
|
2.6
|
%
|
|||||||
|
Construction
work in progress
|
133.4
|
-
|
97.3
|
-
|
|||||||||
|
Total
original cost
|
$
|
3,820.2
|
$
|
3,632.0
|
|||||||||
AFUDC
represents the cost of borrowed and equity funds which are used for construction
purposes, and charged to construction work in progress during the construction
period. AFUDC is included in Other
- net
in the
Consolidated Statements of Income. The total AFUDC capitalized into utility
plant and the portion of which was computed on borrowed and equity funds for
all
periods reported follows:
|
Year
Ended December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
||
|
AFUDC
– borrowed funds
|
$
2.6
|
$
1.6
|
$
1.6
|
||||
|
AFUDC
– equity funds
|
1.5
|
0.3
|
1.6
|
||||
|
Total
AFUDC
|
$
4.1
|
$
1.9
|
$
3.2
|
||||
Maintenance
and repairs, including the cost of removal of minor items of property and
planned major maintenance projects, are charged to expense as incurred. When
property that represents a retirement unit is replaced or removed, the remaining
historical value of such property is charged to Utility
plant,
with an
offsetting charge to Accumulated
depreciation.
Costs
to dismantle and remove retired property are recovered through the depreciation
rates identified above.
Jointly
Owned Plant
SIGECO
and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300
MW
Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the
cost of this unit at December 31, 2006 is $63.2 million with accumulated
depreciation totaling $43.5 million. AGC and SIGECO also share equally in the
cost of operation and output of the unit. SIGECO's share of operating costs
is
included in Other
operating
expenses
in the Consolidated Statements of Income.
| E. |
Nonutility
Property
|
Nonutility
property,
net of
accumulated depreciation and amortization follows:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
|
|||
|
Computer
hardware & software
|
$
|
107.7
|
$
|
105.6
|
|||
|
Land
& buildings
|
73.4
|
69.5
|
|||||
|
Coal
mine development costs & equipment
|
59.7
|
50.0
|
|||||
|
Vehicles &
equipment
|
33.0
|
1.1 | |||||
|
All
other
|
20.6
|
14.1
|
|||||
|
Nonutility
property - net
|
$
|
294.4
|
$
|
240.3
|
|||
The
depreciation of nonutility property is charged against income over its estimated
useful life (ranging from 5 to 40 years), using the straight-line method of
depreciation or units-of-production method of amortization. Repairs and
maintenance, which are not considered improvements and do not extend the useful
life of the nonutility property, are charged to expense as incurred. When
nonutility property is retired, or otherwise disposed of, the asset and
accumulated depreciation are removed, and the resulting gain or loss is
reflected in income. Nonutility property is presented net of accumulated
depreciation and amortization totaling $217.0 million and $144.6 million as
of
December 31, 2006, and 2005, respectively. For the years ended December 31,
2006, 2005, and 2004, the Company capitalized interest totaling $1.2 million,
$0.4 million, and $1.4 million, respectively, on nonutility plant construction
projects.
| F. |
Goodwill
|
Goodwill
arising from business combinations is accounted for in accordance with SFAS
No.
142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 requires a
portion of goodwill be charged to expense only when it is impaired. The Company
tests its goodwill for impairment at a reporting unit level at least annually
and that test is performed at the beginning of each year. Impairment reviews
consist 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 is recognized in operations. Through December 31, 2006,
no
goodwill impairments have been recorded. Approximately $205.0 million of the
Company’s goodwill is included in the Gas Utility Services operating segment.
The remaining $32.8 million is attributable to the Nonutility Group.
| G. |
Regulation
|
Retail
public utility operations affecting Indiana customers are subject to regulation
by the IURC, and retail public utility operations affecting Ohio customers
are
subject to regulation by the PUCO. The Company’s accounting policies give
recognition to the rate-making and accounting practices of these agencies and
to
accounting principles generally accepted in the United States, including the
provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation” (SFAS 71).
Refundable
or Recoverable Gas Costs and Cost of Fuel & Purchased
Power
All
metered gas rates contain a gas cost adjustment clause that allows the Company
to charge for changes in the cost of purchased gas. Metered electric rates
contain a fuel adjustment clause that allows for adjustment in charges for
electric energy to reflect changes in the cost of fuel. The net energy cost
of
purchased power, subject to an agreed upon benchmark, is also recovered through
regulatory proceedings. The Company records any under-or-over-recovery resulting
from gas and fuel adjustment clauses each month in revenues. A corresponding
asset or liability is recorded until the under or over-recovery is billed or
refunded to utility customers. The cost of gas sold is charged to operating
expense as delivered to customers, and the cost of fuel for electric generation
is charged to operating expense when consumed.
Regulatory
Assets and Liabilities
Regulatory
assets represent probable future revenues associated with certain incurred
costs, which will be recovered from customers through the ratemaking process.
Regulatory liabilities represent probable expenditures by the Company for
removal costs or future reductions in revenues associated with amounts that
are
to be credited to customers through the ratemaking process. The Company assesses
the recoverability of costs recognized as regulatory assets and liabilities
and
the ability to continue to account for its activities based on the criteria
set
forth in SFAS 71. Based on current regulation, the Company believes such
accounting is appropriate. If all or part of the Company's operations cease
to
meet the criteria of SFAS 71, a write-off of related regulatory assets and
liabilities could be required. In addition, the Company would be required to
determine any impairment to the carrying value of its utility plant and other
regulated assets.
Regulatory
assets
consist
of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Future
amounts recoverable from ratepayers related to:
|
|||||||
|
Benefit
obligations
|
$
|
46.7
|
$
|
-
|
|||
|
Income
taxes
|
13.3
|
11.1
|
|||||
|
Asset
retirement obligations & other
|
5.2
|
1.7
|
|||||
|
65.2
|
12.8
|
||||||
|
Amounts
deferred for future recovery related to:
|
|||||||
|
Demand
side management programs
|
27.7
|
26.7
|
|||||
|
MISO-related
costs
|
17.1
|
9.4
|
|||||
|
Cost
recovery riders & other
|
4.7
|
2.5
|
|||||
|
49.5
|
38.6
|
||||||
|
Amounts
currently recovered through base rates related to:
|
|||||||
|
Unamortized
debt issue costs
|
23.1
|
20.2
|
|||||
|
Premiums
paid to reacquire debt
|
6.0
|
6.5
|
|||||
|
Demand
side management programs & other
|
3.3
|
4.5
|
|||||
|
32.4
|
31.2
|
||||||
|
Amounts
currently recovered through tracking mechanisms related
to:
|
|||||||
|
Ohio
authorized trackers
|
10.3
|
5.6
|
|||||
|
Indiana
authorized trackers
|
6.1
|
1.7
|
|||||
|
16.4
|
7.3
|
||||||
|
Total
regulatory assets
|
$
|
163.5
|
$
|
89.9
|
|||
Of
the
$32.4 million currently being recovered through base rates charged to customers,
$1.5 million is earning a return. The weighted average recovery period of
regulatory assets currently being recovered is 14.4 years. The Company has
rate
orders for all deferred costs not yet in rates and therefore believes that
future recovery is probable.
Regulatory
liabilities
consist
of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Advances
from rate-payers related to:
|
|||||||
|
Cost
of removal
|
$
|
270.6
|
$
|
251.4
|
|||
|
Asset
retirement obligations
|
11.3
|
11.6
|
|||||
|
281.9
|
263.0
|
||||||
|
Amounts
currently amortizing related to:
|
|||||||
|
Interest
rate hedging proceeds (See Note 15)
|
6.1
|
6.8
|
|||||
|
Amounts
deferred for future settlement related to:
|
|||||||
|
MISO-related
costs
|
3.1
|
3.1
|
|||||
|
Total
regulatory liabilities
|
$
|
291.1
|
$
|
272.9
|
|||
Cost
of Removal
The
Company collects an estimated cost of removal of its utility plant through
depreciation rates established in regulatory proceedings. The Company records
amounts expensed in advance of payments as a Regulatory
liability
because
the liability does not meet the threshold of an asset retirement obligation
as
defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its
related interpretations (SFAS 143).
Asset
Retirement Obligations
A
portion
of removal costs related to interim retirements of gas utility pipeline
and
utility poles, certain asbestos-related issues, and reclamation activities
meet
the definition of an asset retirement obligation (ARO). The regulatory
liability
above represents a timing difference between cost recognition described
in SFAS
143, and cost recognition established in regulatory proceedings for these
obligations.
| H. |
Asset
Retirement Obligations
|
SFAS
No.
143 requires entities to record the fair value of a liability for a legal
ARO 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, 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. To the extent regulation is involved, such gain
or loss
may be deferred.
Asset
retirement obligations total $20.8 million at both December 31, 2006 and
2005,
and are included in Other
Liabilities.
During
2006, the Company recorded reductions in estimates totaling $1.2 million
and
accretion of $1.2 million. In 2005, the Company recorded accretion of $0.3
million and recorded additional liabilities of $16.1 million. Of those
additions, $16.0 million were recognized upon adoption of FASB Interpretation
No. 47.
| I. |
Impairment
Review of Long-Lived Assets
|
Long-lived
assets are reviewed as facts and circumstances indicate that the carrying amount
may be impaired. This review is performed in accordance with SFAS No. 144
“Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144).
SFAS 144 establishes one accounting model for all impaired long-lived assets
and
long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires
that
the evaluation for impairment involve the comparison of an asset’s carrying
value to the estimated future cash flows that the asset is expected to generate
over its remaining life. If this evaluation were to conclude that the carrying
value of the asset is impaired, an impairment charge would be recorded based
on
the difference between the asset’s carrying amount and its fair value (less
costs to sell for assets to be disposed of by sale) as a charge to operations
or
discontinued operations.
| J. |
Comprehensive
Income
|
Comprehensive
income is a measure of all changes in equity that result from the
non-shareholder transactions. This information is reported in the Consolidated
Statements of Common Shareholders' Equity. A summary of the components of and
changes in Accumulated
other comprehensive income
for the
past three years follows:
|
2004
|
2005
|
2006
|
||||||||||||||||||||
|
Beginning
|
|
Changes
|
|
End
|
|
Changes
|
|
End
|
|
Changes
|
|
End
|
|
|||||||||
|
|
|
of
Year
|
|
During
|
|
of
Year
|
|
During
|
|
of
Year
|
|
During
|
|
of
Year
|
|
|||||||
|
(In
millions)
|
|
Balance
|
|
Year
|
|
Balance
|
|
Year
|
|
Balance
|
|
Year
|
|
Balance
|
||||||||
|
Unconsolidated
affiliates
|
$
|
10.5
|
$
|
(6.4
|
)
|
$
|
4.1
|
$
|
(4.6
|
)
|
$
|
(0.5
|
)
|
$
|
10.7
|
10.2
|
||||||
|
Pension
& other benefit costs
|
(29.2
|
)
|
(0.1
|
)
|
(29.3
|
)
|
0.3
|
(29.0
|
)
|
26.5
|
(2.5
|
)
|
||||||||||
|
Cash
flow hedges
|
-
|
-
|
-
|
6.7
|
6.7
|
(6.0
|
)
|
0.7
|
||||||||||||||
|
Deferred
income taxes
|
7.6
|
2.6
|
10.2
|
(1.0
|
)
|
9.2
|
(12.5
|
)
|
(3.3
|
)
|
||||||||||||
|
Accumulated
other
comprehensive
income (loss)
|
$
|
(11.1
|
)
|
$
|
(3.9
|
)
|
$
|
(15.0
|
)
|
$
|
1.4
|
$
|
(13.6
|
)
|
$
|
18.7
|
$
|
5.1
|
||||
Accumulated
other comprehensive income arising from unconsolidated affiliates is primarily
the Company’s portion of ProLiance Energy, LLC’s accumulated comprehensive
income related to use of cash flow hedges, including commodity contracts, and
the Company’s portion of Haddington Energy Partners, LP’s accumulated
comprehensive income related to unrealized gains and losses on marketable
securities. (See Note 3 for more information on unconsolidated
affiliates.)
| K. |
Revenues
|
Revenues
are recorded as products and services are delivered to customers. To more
closely match revenues and expenses, the Company records revenues for all gas
and electricity delivered to customers but not billed at the end of the
accounting period.
| L. |
Excise
and Utility Receipts Taxes
|
Excise
taxes and a portion of utility receipts taxes are included in rates charged
to
customers. Accordingly, the Company records these taxes received as a component
of operating revenues, which totaled $39.7 million in 2006, $42.6 million in
2005, and $38.3 million in 2004. Expense associated with excise and utility
receipts taxes are recorded as a component of Taxes
other than income taxes.
| M. |
Use
of Estimates
|
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 financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
| N. |
Other
Significant Policies
|
Included
elsewhere in these Notes are significant accounting policies related to
investments in unconsolidated affiliates (Note 3), income taxes (Note 6),
earnings per share (Note 11), and derivatives (Note 15).
As
more
fully described in Note 9, the Company applied the intrinsic method prescribed
in APB Opinion 25, “Accounting for Stock Issued to Employees” (APB 25) and
related interpretations when measuring compensation expense for its share-based
compensation plans in the years prior to 2006. The exercise price of stock
options awarded under the Company’s stock option plans equaled the fair market
value of the underlying common stock on the date of grant. Accordingly, no
compensation expense was recognized related to stock option plans prior to
2006.
The Company also maintains restricted stock and phantom stock plans for
executives, employees, and non-employee directors that result in share-based
compensation expense recognized in reported net income consistent with expense
that would have been recognized if the Company used the fair value based method
prescribed in SFAS No. 123 “Accounting for Stock-Based Compensation” (SFAS 123)
in those years. For the years ended December 31, 2005 and 2004, the effect
on
net income and earnings per share as if the fair value based method prescribed
in SFAS 123 had been applied follows:
|
Year
Ended December 31,
|
|||||||
|
(In
millions, except per share amounts)
|
2005
|
|
2004
|
||||
|
Net
Income as reported:
|
$
|
136.8
|
$
|
107.9
|
|||
|
Share-based
employee compensation included in reported net income-net of
tax
|
2.1
|
1.7
|
|||||
|
Total
share-based employee compensation expense determined under fair
value
|
|||||||
|
based
method for all awards-net of tax
|
(2.8
|
)
|
(2.6
|
)
|
|||
|
Pro
forma
|
$
|
136.1
|
$
|
107.0
|
|||
|
Basic
earnings per share as reported:
|
$
|
1.81
|
$
|
1.43
|
|||
|
Basic
earnings per share pro forma:
|
1.80
|
1.42
|
|||||
|
Diluted
earnings per share as reported:
|
$
|
1.80
|
$
|
1.42
|
|||
|
Diluted
earnings per share pro forma:
|
1.79
|
1.41
|
|||||
| 3. |
Investments
in Unconsolidated
Affiliates
|
Investments
in unconsolidated affiliates where the Company has significant influence are
accounted for using the equity method of accounting. The Company’s share of net
income or loss from these investments is recorded in Equity
in earnings of unconsolidated affiliates.
Dividends are recorded as a reduction of the carrying value of the investment
when received. Investments in unconsolidated affiliates where the Company does
not have significant influence are accounted for using the cost method of
accounting and include adjustments for declines in value judged to be other
than
temporary. Dividends are recorded as Other
- net
when
received.
Investments
in unconsolidated affiliates
consist
of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
ProLiance
Energy, LLC
|
$
|
146.7
|
$
|
136.5
|
|||
|
Haddington
Energy Partnerships
|
13.8
|
10.8
|
|||||
|
Reliant
Services, LLC
|
2.8
|
29.3
|
|||||
|
Utilicom
Networks, LLC & related entities
|
-
|
11.7
|
|||||
|
Pace
Carbon Synfuels, LP
|
-
|
9.6
|
|||||
|
Other
partnerships & corporations
|
17.7
|
16.8
|
|||||
|
Total
investments in unconsolidated affiliates
|
$
|
181.0
|
$
|
214.7
|
|||
ProLiance
Energy, LLC
ProLiance
Energy, LLC (ProLiance), a nonutility gas marketing and energy management
affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides
services to a broad range of municipalities, utilities, industrial operations,
schools, and healthcare institutions located throughout the Midwest and
Southeast United States. ProLiance’s primary customers include Vectren’s Indiana
utilities and nonutility gas supply operations as well as Citizens Gas.
ProLiance’s primary businesses include gas marketing, gas portfolio
optimization, and other portfolio and energy management services. The Company,
including its retail gas supply operations, contracted for 75% of its natural
gas purchases through ProLiance in 2006. Pre-tax income of $35.3 million, $52.4
million, and $25.9 million was recognized as ProLiance’s contribution to
earnings for the years ended December 31, 2006, 2005, and 2004, respectively.
ProLiance is a significant subsidiary for the purposes of Regulation S-X,
paragraph 3.09, as promulgated by the SEC.
Summarized
Financial Information
|
Year
Ended December 31,
|
||||||||||
|
(in
millions)
|
|
2006
|
|
2005
|
|
2004
|
||||
|
Summarized
Statement of Income information:
|
||||||||||
|
Revenues
|
$
|
2,506.2
|
$
|
3,237.0
|
$
|
2,573.8
|
||||
|
Margin
|
106.3
|
116.0
|
74.0
|
|||||||
|
Operating
income
|
74.5
|
87.1
|
43.2
|
|||||||
|
ProLiance's
earnings
|
57.9
|
86.0
|
42.6
|
|||||||
|
As
of December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Summarized
balance sheet information:
|
|||||||
|
Current
assets
|
$
|
641.3
|
$
|
870.2
|
|||
|
Noncurrent
assets
|
41.5
|
50.7
|
|||||
|
Current
liabilities
|
445.0
|
698.2
|
|||||
|
Noncurrent
liabilities
|
1.8
|
3.3
|
|||||
|
Equity
|
236.0
|
219.4
|
|||||
Vectren’s
share of ProLiance’s earnings, after income taxes and allocated interest
expense, was $18.3 million, $31.1 million, and $15.4 million for the years
ended
December 31, 2006, 2005, and 2004, respectively.
Transactions
with ProLiance
Purchases
from ProLiance for resale and for injections into storage for the years ended
December 31, 2006, 2005, and 2004, totaled $777.0 million, $1,049.3 million,
and
$875.9 million, respectively. Amounts owed to ProLiance at December 31, 2006,
and 2005, for those purchases were $84.8 million and $159.1 million,
respectively, and are included in Accounts
payable to affiliated companies
in the
Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.
Vectren
received regulatory approval on April 25, 2006, from the IURC for ProLiance
to
provide natural gas supply services to the Company’s Indiana utilities through
March 2011. ProLiance has not provided gas supply/portfolio administration
services to VEDO since October 31, 2005.
ProLiance
Lawsuit Settlement
On
November 22, 2006, ProLiance agreed to settle a 2002 civil lawsuit between
the
City of Huntsville, Alabama and ProLiance. The $21.6 million settlement
(Huntsville Settlement) relates to a dispute over a contractual relationship
with Huntsville Utilities during 2000-2002.
During
2006, ProLiance recorded an $18.3 million charge recognizing the Huntsville
Settlement. During 2004, ProLiance recorded $3.9 million as a reserve for loss
contingency recognizing the initial unfavorable judgment and the uncertainties
related to ultimate outcome. During 2006 and 2005, $0.1 million and $0.5 million
of legal fees were charged against the reserve.
As
an
equity investor in ProLiance, Vectren recorded its share of these charges which
totaled $6.6 million after tax in 2006 and $1.4 million after tax in 2004.
Vectren is currently exploring whether a portion of those charges may be
recoverable from insurance carriers.
Commodity
Prices
In
response to the effects of higher gas costs, ProLiance increased its unsecured
revolving credit facilities. Those facilities expire in June 2009. These
facilities total $400 million from October 1 through March 31 and $300 million
from April 1 through September 30. These credit facilities are not guaranteed
by
Vectren Corporation.
Haddington
Energy Partnerships
The
Company has an approximate 40% ownership interest in Haddington Energy Partners,
LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II). On
a
combined basis, these partnerships raised a total of $67 million to invest
in
energy related ventures. As of December 31, 2006, the Company has no further
commitments to invest in either Haddington I or II. As of December 31, 2006,
these Haddington ventures have two remaining investments related to compressed
air storage and liquefied natural gas storage. Both Haddington ventures
are investment companies accounted for using the equity method of
accounting. Pre-tax earnings of $0.3 million, $7.7 million, and $4.5
million were recognized as the partnerships’ contribution to earnings for the
years ended December 31, 2006, 2005 and 2004, respectively.
The
following is summarized financial information as to the assets, liabilities,
and
results of operations of the Haddington Partnerships. For the year ended
December 31, 2006, revenues, operating loss, and net loss were (in millions)
zero, $(0.3), and $(0.3), respectively. For the year ended December 31, 2005,
revenues, operating income, and net income were (in millions) $13.2, $12.4,
and
$22.2, respectively. For the year ended December 31, 2004, revenues, operating
income, and net income were (in millions) $3.3, $2.5, and $9.6, respectively.
As
of December 31, 2006, investments, other assets, and liabilities were (in
millions) $31.3, $1.1, and zero, respectively. As of December 31, 2005,
investments, other assets, and liabilities were (in millions) $25.0, $1.2,
and
zero, respectively.
Pace
Carbon Synfuels, LP
Pace
Carbon Synfuels, LP (Pace Carbon) is a Delaware limited partnership formed
to
develop, own, and operate four projects to produce and sell coal-based synthetic
fuel (synfuel) utilizing Covol technology. The Company has an 8.3 percent
interest in Pace Carbon which is accounted for using the equity method of
accounting. The Internal Revenue Code provides for manufacturers, such as
Pace Carbon, to receive a tax credit for every ton of synthetic fuel sold.
Under current tax laws, these synfuel related credits and fees cease at the
end
of 2007.
The
Internal Revenue Service has issued private letter rulings, which concluded
that
the synthetic fuel produced at the Pace Carbon facilities should qualify for
tax
credits. The IRS has completed tax audits of Pace Carbon for the years
1998 through 2001 without challenging tax credit calculations. As a
partner in Pace Carbon, Vectren has reflected synfuel tax credits in its
consolidated results from inception through December 31, 2006, of approximately
$92 million, of which approximately $81 have been generated since 2001. To
date,
Vectren has been in a position to utilize or carryforward substantially all
of
the credits generated. Primarily from the use of these credits, the Company
generated an Alternative Minimum Tax (AMT) credit carryforward. The Company
has
an accumulated AMT credit carryforward of approximately $42.1 million at
December 31, 2006.
Synfuel
tax credits are only available when the price of oil is less than a base price
specified by the Internal Revenue Code, as adjusted for inflation. The
Company estimates that high oil prices caused a 35 percent phase out of synfuel
tax credits in 2006. Therefore, of the $21.5 million tax credits generated
in
2006, only $14.0 million are reflected as a reduction to the Company’s
Income
taxes.
In
July
2006, the Company suspended its participation in the production of synthetic
fuel due to the high price of oil and uncertainty of federal legislation that
might favorably affect the reference price of oil governing the phase out of
synfuel tax credits. Consistent with that decision to suspend
participation, the Company impaired its investment in Pace Carbon and expensed
funding requirements estimated at that time. Charges approximating $9.5
million, or $5.7 million after tax, were recorded in Other-net
in the
second quarter of 2006. The Company resumed participation in October 2006 as
oil
prices began to fall.
For
the
year ended December 31, 2006, synfuel-related activity, inclusive of the phase
out of tax credits, the impairment of synfuel-related assets, the related
hedging activity, and estimated impact of insurance contracts, resulted in
an
after tax loss of $3.8 million, or $0.05 per share. Mark-to-market losses
associated with financial contracts hedging 2007 production recognized in 2006
totaled $1.5 million after tax, or $0.02 per share. In 2005 and 2004,
synfuel-related earnings totaled $11.7 million and $12.1 million, respectively.
The investment in Pace Carbon resulted in losses reflected in Equity
in earnings of unconsolidated affiliates
totaling
$17.8 million in 2006, $15.7 million in 2005, and $12.0 million in
2004.
The
following is summarized financial information as to the assets, liabilities,
and
results of operations of Pace Carbon. For the year ended December 31, 2006,
revenues, margin, operating loss, and net loss were (in millions) $389.7,
($116.4), ($175.5), and ($176.8), respectively. For the year ended December
31,
2005, revenues, margin, operating loss, and net loss were (in millions) $333.4,
($135.3), ($170.3), and ($175.7), respectively. For the year ended December
31,
2004, revenues, margin, operating loss, and net loss were (in millions) $243.0,
($99.8), ($128.6), and ($141.1), respectively. As of December 31, 2006, current
assets, noncurrent assets, current liabilities, and noncurrent liabilities
were
(in millions) $61.3, $54.4, $46.6, and $36.5, respectively. As of December
31,
2005, current assets, noncurrent assets, current liabilities, and noncurrent
liabilities were (in millions) $72.8, $53.0, $43.4, and $24.5,
respectively.
Utilicom
Networks, LLC & Related Entities
The
Company had an approximate 2% equity interest and a convertible subordinated
debt investment in Utilicom Networks, LLC (Utilicom). The Company also had
an
approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which
was
formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides
broadband services, such as cable television, high-speed internet, and advanced
local and long distance phone services, to the greater Evansville, Indiana
area.
The Company accounted for its investments in Utilicom and Holdings using the
cost method of accounting.
Other
Utilicom-related subsidiaries also owned franchising agreements to provide
broadband services to the greater Indianapolis, Indiana and Dayton, Ohio
markets. In 2004, the build out of these markets was further evaluated, and
the
Company concluded that it was unlikely it would make additional investments
in
those markets. As a result, the Company recorded charges totaling $6.0 million,
or $3.6 million after-tax, to write off investments made in the Indianapolis
and
Dayton markets and to write down its investment in SIGECOM.
In
August
2006, SIGECOM’s majority owner and the Company sold their interests in SIGECOM
to WideOpenWest, LLC. Resulting
from the sale, the Company recorded a loss of $1.3 million after tax in
2006. Proceeds to the Company, which include the settlement of notes receivable,
are expected to total approximately $45 million. The Company anticipates
receiving the proceeds in early 2007. Since proceeds are expected in 2007,
the
Company has classified these expected proceeds in Current
assets.
Undistributed
Earnings of Unconsolidated Affiliates
As
of
December 31, 2006, undistributed earnings of unconsolidated affiliates
approximated $127 million and are primarily comprised of the undistributed
earnings of ProLiance.
| 4. |
Miller
Pipeline Corporation
Acquisition
|
Effective
July 1, 2006, the Company purchased the remaining 50% ownership in Miller
Pipeline Corporation (Miller), making Miller a wholly owned subsidiary. The
results of Miller’s operations, formerly accounted for using the equity method,
have been included in consolidated results since July 1, 2006. Based on
current accounting rules, Miller is consolidated on a prospective basis only.
Prior periods were not restated.
Miller,
originally founded in 1953, performs natural gas and water distribution,
transmission, and construction repair and rehabilitation primarily in the
Midwest and the repair and rehabilitation of gas, water, and wastewater
facilities nationwide. Miller’s customers include Vectren’s utilities.
While
the
acquisition of Miller is not expected to have a material impact on the overall
financial statements, consolidating Miller resulted in, among other impacts,
a
$77.6 million increase in Nonutility
revenues
and a
$60.8 million increase in Other
operating expense when
compared to 2005 and 2004. The transaction also increased consolidated
Goodwill
by
approximately $31 million, intangible assets, which are included in Other
assets,
by $14
million, and $24 million in Long-term
debt.
The
Company is in the process of completing the asset valuation process regarding
deferred taxes and intangible assets; thus, the allocation of the purchase
price
is not complete and is subject to change. Of the $31 million of goodwill,
approximately $0.9 million is not deductible for tax purposes based upon
the
current purchase price allocation.
Prior
to
this transaction, Miller was 100 percent owned by Reliant Services, LLC
(Reliant). Reliant, a 50% owned strategic alliance with an affiliate of Duke
Energy Corporation, is accounted for using the equity method of accounting,
and
previously provided facilities locating and meter reading services to the
Company’s utilities. For the years ended December 31, 2006, 2005, and 2004, fees
paid to Reliant for locating and meter reading services as well as for Miller’s
construction-related services totaled $15.9 million, $21.3 million, and $31.2
million, respectively. Amounts charged are market based. Amounts owed to Reliant
totaled less than $0.1 million at December 31, 2006 and $3.2 million at December
31, 2005, and are included in Accounts
payable to affiliated companies
in the
Consolidated Balance Sheets. Reliant exited the meter reading and facilities
locating businesses in 2006.
| 5. |
Other
Investments
|
Other
investments consist of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Leveraged
leases
|
$
|
31.0
|
$
|
32.6
|
|||
|
Convertible
notes receivable from Utilicom-related entities (See Note
3)
|
-
|
33.1
|
|||||
|
Other
investments
|
43.5
|
45.9
|
|||||
|
Total
other investments
|
$
|
74.5
|
$
|
111.6
|
|||
Leveraged Leases
The
Company is a lessor in three leveraged lease agreements under which real estate
or equipment is leased to third parties. The total equipment and facilities
cost
was approximately $76.2 million at both December 31, 2006, and 2005,
respectively. The cost of the equipment and facilities was partially financed
by
non-recourse debt provided by lenders who have been granted an assignment of
rentals due under the leases and a security interest in the leased property,
which they accepted as their sole remedy in the event of default by the lessee.
Such debt amounted to approximately $47.4 million and $44.5 million at December
31, 2006, and 2005, respectively. At December 31, 2006 and 2005, the Company’s
leveraged lease investment, net of related deferred tax liabilities, was $10.2
million and $7.8 million, respectively.
Other
Investments
Other
investments include other notes receivable, the cash surrender value of life
insurance policies, restricted cash, and a municipal bond, among other
items.
| 6. |
Income
Taxes
|
The
liability method of accounting is used for income taxes under which deferred
income taxes are recognized to reflect the tax effect of temporary differences
between the book and tax bases of assets and liabilities at currently enacted
income tax rates. Significant components of the net deferred tax liability
follow:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Noncurrent
deferred tax liabilities (assets):
|
|||||||
|
Depreciation
& cost recovery timing differences
|
$
|
297.0
|
$
|
288.3
|
|||
|
Leveraged
leases
|
20.8
|
24.8
|
|||||
|
Regulatory
assets recoverable through future rates
|
21.0
|
19.3
|
|||||
|
Demand
side management programs
|
8.4
|
7.7
|
|||||
|
Other
comprehensive income
|
2.5
|
(9.2
|
)
|
||||
|
Alternative
minimum tax carryforward
|
(42.1
|
)
|
(47.4
|
)
|
|||
|
Employee
benefit obligations
|
(39.2
|
)
|
(36.0
|
)
|
|||
|
Net
operating loss & other carryforwards
|
(10.1
|
)
|
(1.7
|
)
|
|||
| Regulatory liabilities to be settled through future rates | (7.7 | ) | (8.2 | ) | |||
|
Other
– net
|
10.1
|
(10.3
|
)
|
||||
|
Net
noncurrent deferred tax liability
|
260.7
|
227.3
|
|||||
|
Current
deferred tax (assets)/liabilities:
|
|||||||
|
Deferred
fuel costs-net
|
(1.8
|
)
|
7.6
|
||||
|
Other
– net
|
(1.8
|
)
|
-
|
||||
|
Net
current deferred tax (asset)/liability
|
(3.6
|
)
|
7.6
|
||||
|
Net
deferred tax liability
|
$
|
257.1
|
$
|
234.9
|
|||
At December 31, 2006, and 2005, investment tax credits totaling $9.9 million and $11.8 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. At December 31, 2006, the Company has alternative minimum tax carryforwards of $42.1 million, which do not expire and $1.6 million of other tax credit carryforwards that expire in approximately 20 years. In addition, the Company has $8.3 million in net operating loss carryforwards that relate to the acquisition of Miller, which will expire in 5 to 20 years.
The
components of income tax expense and utilization of investment tax credits
follow:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|||||
|
Current:
|
||||||||||
|
Federal
|
$
|
18.2
|
$
|
37.9
|
$
|
24.1
|
||||
|
State
|
10.7
|
14.8
|
9.0
|
|||||||
|
Total
current taxes
|
28.9
|
52.7
|
33.1
|
|||||||
|
Deferred:
|
||||||||||
|
Federal
|
7.0
|
(6.0
|
)
|
3.8
|
||||||
|
State
|
(3.6
|
)
|
(0.2
|
)
|
4.3
|
|||||
|
Total
deferred taxes
|
3.4
|
(6.2
|
)
|
8.1
|
||||||
|
Amortization
of investment tax credits
|
(2.0
|
)
|
(2.4
|
)
|
(2.2
|
)
|
||||
|
Total
income tax expense
|
$
|
30.3
|
$
|
44.1
|
$
|
39.0
|
||||
A
reconciliation of the federal statutory rate to the effective income tax rate
follows:
|
Year
Ended December 31,
|
||||||||||
|
2006
|
|
2005
|
|
2004
|
||||||
|
Statutory
rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
||||
|
State
and local taxes-net of federal benefit
|
5.7
|
5.5
|
5.9
|
|||||||
|
Synfuel
tax credits
|
(9.6
|
)
|
(12.3
|
)
|
(11.6
|
)
|
||||
|
Adjustment
of income tax accruals
|
(2.0
|
)
|
(1.9
|
)
|
(0.1
|
)
|
||||
|
Tax
law change
|
(2.5
|
)
|
-
|
-
|
||||||
|
Amortization
of investment tax credit
|
(1.4
|
)
|
(1.3
|
)
|
(1.5
|
)
|
||||
|
Depletion
|
(1.6
|
)
|
(1.0
|
)
|
(0.6
|
)
|
||||
|
Other
tax credits
|
(0.5
|
)
|
(0.4
|
)
|
(0.6
|
)
|
||||
|
All
other-net
|
(1.3
|
)
|
0.8
|
-
|
||||||
|
Effective
tax rate
|
21.8
|
%
|
24.4
|
%
|
26.5
|
%
|
||||
| 7. |
Retirement
Plans & Other Postretirement
Benefits
|
At
December 31, 2006, the Company maintains three qualified defined benefit pension
plans, a nonqualified supplemental executive retirement plan (SERP), and three
other postretirement benefit plans. The defined benefit pension and other
postretirement benefit plans, which cover eligible full-time regular employees,
are primarily noncontributory. The postretirement health care and life insurance
plans are a combination of self-insured and fully insured plans. The Company
has
Voluntary Employee Beneficiary Association (VEBA) Trust Agreements for the
partial funding of postretirement health benefits for retirees and their
eligible dependents and beneficiaries. Annual VEBA funding is discretionary.
To
the extent these postretirement benefits are funded, the benefits are not
liabilities in these consolidated financial statements. The detailed disclosures
of benefit components that follow are based on an actuarial valuation using
a
measurement date as of September 30. The qualified pension plans and the SERP
are aggregated under the heading “Pension Benefits.” Other postretirement
benefit plans are aggregated under the heading “Other Benefits.”
Adoption
of SFAS 158
On
December 31, 2006,
and
after
calculating the balance sheet impact of the Company’s retirement plans using the
accounting guidance prescribed by SFAS 87 and SFAS 106, the Company adopted
SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and
132(R)” (SFAS 158). SFAS 158 requires the Company to recognize the funded
status of its pension plans and postretirement plans. SFAS 158 defines the
funded status of a defined benefit plan as its assets less its projected benefit
obligation, which includes projected salary increases, and defines the funded
status of a postretirement plan as its assets less its accumulated
postretirement benefit obligation. To the extent this obligation exceeded
amounts previously recognized, the Company recorded a Regulatory
Asset
for that
portion related to its cost-based and rate regulated utilities. To the extent
that excess liability did not relate to a cost-based rate-regulated utility,
the
offset was recorded as a reduction to equity in Accumulated
Other Comprehensive Income.
As
a result of adopting this standard, the Company’s assets increased $30.0
million, its liabilities increased $22.0 million and its equity increased $8.0
million.
SFAS
158
also requires an employer to measure the funded status of a plan as of the
date
of its year-end balance sheet and requires disclosure in the notes to financial
statements certain additional information related to net periodic benefit cost
for the next fiscal year. The measurement date provisions are not required
to be
adopted until 2008.
Balances
related to retirement plans by balance sheet classification as of December
31,
2005, are presented with the effects of adopting SFAS 158 as of December 31,
2006, as follows.
|
(In
Millions)
|
|
|
2005
Balance
|
|
2006
Balance
Pre
SFAS
158
|
|
Changes
Resulting
from
Adoption
of SFAS 158
|
|
2006
Ending Balance
|
|||||||
|
Other
Long-term Liabilities
|
||||||||||||||||
| Net Amount Recognized Related To | ||||||||||||||||
|
Other
Benefit Obligations
|
$
|
(61.8
|
)
|
$
|
(60.6
|
)
|
$
|
4.5
|
$
|
(56.1
|
)
|
|||||
|
Pension
Obligations
|
(13.6
|
)
|
(15.7
|
)
|
(40.3
|
)
|
(56.0
|
)
|
||||||||
|
SERP
Obligations
|
(9.1
|
)
|
(9.5
|
)
|
(3.0
|
)
|
(12.5
|
)
|
||||||||
|
Additional
Minumum Pension Liability
|
(41.6
|
)
|
(28.2
|
)
|
28.2
|
-
|
||||||||||
|
$
|
(126.1
|
)
|
$
|
(114.0
|
)
|
$
|
(10.6
|
)
|
$
|
(124.6
|
)
|
|||||
|
Accrued
Liabilities
|
||||||||||||||||
|
Other
Benefit Obligations
|
$
|
-
|
$
|
-
|
$
|
(5.5
|
)
|
$
|
(5.5
|
)
|
||||||
|
SERP
Obligation
|
-
|
-
|
(0.8
|
)
|
(0.8
|
)
|
||||||||||
|
|
$ | - |
$
|
-
|
$
|
(6.3
|
)
|
$
|
(6.3
|
)
|
||||||
|
Other
Long-term Assets
|
||||||||||||||||
|
Prepaid
Pension Asset
|
$
|
3.1
|
$
|
4.2
|
$
|
(4.2
|
)
|
$
|
-
|
|||||||
|
Intangible
Asset
|
12.6
|
12.5
|
(12.5
|
)
|
-
|
|||||||||||
|
$
|
15.7
|
$
|
16.7
|
$
|
(16.7
|
)
|
$
|
-
|
||||||||
|
Regulatory
Assets
|
$
|
-
|
$
|
-
|
$
|
46.7
|
$
|
46.7
|
||||||||
|
Deferred
Income Taxes
|
$
|
11.8
|
$
|
6.4
|
$
|
(5.2
|
)
|
$
|
1.2
|
|||||||
|
Accumulated
Other Comprehensive Income
|
$
|
17.2
|
$
|
9.3
|
$
|
(8.0
|
)
|
$
|
1.3
|
|||||||
Following
is a reconciliation of the amounts remaining in accumulated other comprehensive
income (AOCI) related to retirement plan obligations as of December 31, 2006
and
amounts expected to be amortized to earnings in 2007.
|
(In
Millions)
|
As
Of December 31, 2006
|
Expected
to Amortized in 2007
|
|||||||||||
|
Pensions
|
|
Other
Benefits
|
|
Pensions
|
|
Other
Benefits
|
|||||||
|
Prior
Service Cost
|
$
|
12.9
|
$
|
(5.5
|
)
|
$
|
1.7
|
$
|
(0.8
|
)
|
|||
|
Unamortized
Actuarial Gain/(Loss)
|
35.4
|
(2.3
|
)
|
1.5
|
(0.1
|
)
|
|||||||
|
Transition
Obligation
|
-
|
8.7
|
-
|
1.1
|
|||||||||
|
48.3
|
0.9
|
$
|
3.2
|
$
|
0.2
|
||||||||
|
Less
Regualtory Asset Deferral
|
(45.9
|
)
|
(0.8
|
)
|
|||||||||
|
AOCI
Balance Before Taxes
|
$
|
2.4
|
$
|
0.1
|
|||||||||
Net
Periodic Benefit Costs
A
summary
of the components of net periodic benefit cost for the three years ended
December 31, 2006, follows:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|
2006
|
|
2005
|
|
2004
|
||||||||
|
Service
cost
|
$
|
6.0
|
$
|
5.6
|
$
|
6.6
|
$
|
0.6
|
$
|
0.7
|
$
|
0.9
|
|||||||
|
Interest
cost
|
14.1
|
13.8
|
13.4
|
3.9
|
4.5
|
5.3
|
|||||||||||||
|
Expected
return on plan assets
|
(13.5
|
)
|
(13.2
|
)
|
(13.5
|
)
|
(0.6
|
)
|
(0.6
|
)
|
(0.7
|
)
|
|||||||
|
Amortization
of prior service cost
|
1.8
|
1.6
|
0.9
|
(0.8
|
)
|
(0.6
|
)
|
-
|
|||||||||||
|
Amortization
of actuarial loss (gain)
|
2.4
|
1.8
|
1.0
|
-
|
(0.2
|
)
|
(0.2
|
)
|
|||||||||||
|
Amortization
of transitional (asset) obligation
|
-
|
(0.2
|
)
|
1.1
|
1.5
|
2.9
|
|||||||||||||
|
Net
periodic benefit cost
|
$
|
10.8
|
$
|
9.6
|
$
|
8.2
|
$
|
4.2
|
$
|
5.3
|
$
|
8.2
|
|||||||
A
portion
of benefit costs are capitalized as Utility
plant.
Costs
capitalized in 2006, 2005, and 2004 approximated $4.3 million, $4.2 million,
and
$4.6 million, respectively.
To
calculate the expected return on plan assets, the Company uses the plan assets’
market-related value and an expected long-term rate of return. The fair market
value of the assets at the measurement date is adjusted to a market-related
value by recognizing the change in fair value experienced in a given year
ratably over a five-year period.
Based
on
a targeted 60% equity, 35% debt, and 5% real estate allocation for the pension
plans, the Company has used a long-term expected rate of return of 8.25% to
calculate 2006 periodic benefit cost. For fiscal 2007, the expected long-term
rate of return will also be 8.25%.
In
January 2005, the Company announced the amendment of certain postretirement
benefit plans, effective January 1, 2006. The amendment resulted in an estimated
$4 million annual decrease in periodic cost, of which approximately $3.1 million
was recognized in 2005.
A union
representing bargaining-unit employees at the Company’s regulated subsidiaries
has advised the Company that it believes that these changes are not permitted
under the existing collective bargaining agreements which govern the
relationship between the employees and the affected subsidiaries. With
assistance from legal counsel, management has analyzed the union’s position and
continues to believe that the Company has reserved the right to amend the
affected plans and that changing these benefits for retirees is not subject
to
mandatory bargaining.
The
weighted averages of significant assumptions used to determine net periodic
benefit costs follow:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|
2006
|
|
2005
|
|
2004
|
||||||||
|
Discount
rate
|
5.50
|
%
|
5.75
|
%
|
6.00
|
%
|
5.50
|
%
|
5.75
|
%
|
6.00
|
%
|
|||||||
|
Rate
of compensation increase
|
3.25
|
%
|
3.50
|
%
|
3.50
|
%
|
3.25
|
%
|
3.50
|
%
|
3.50
|
%
|
|||||||
|
Expected
return on plan assets
|
8.25
|
%
|
8.25
|
%
|
8.50
|
%
|
8.25
|
%
|
8.25
|
%
|
8.50
|
%
|
|||||||
|
Expected
increase in Consumer Price Index
|
N/A
|
N/A
|
N/A
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
||||||||||
Health
care cost trend rate assumptions do not have a material effect on the service
and interest cost components of benefit costs. The Company’s benefit plans limit
Vectren’s exposure to increases in health care costs to annual changes in the
Consumer Price Index (CPI). Any increase in health care costs in excess of
the
CPI increase is the responsibility of the plan participants.
Expected
Cash Flows
In
2007,
the Company expects to make contributions of approximately $8.4 million to
its
pension plan trusts. In addition, the Company expects to make payments totaling
approximately $0.8 million directly to SERP participants and approximately
$4.8
million directly to those participating in other postretirement plans.
Estimated
retiree pension benefit payments, including the SERP, projected to be required
during the years following 2006 (in millions) are $12.9 in 2007, $12.9 in 2008,
$13.4 in 2009 $14.2 in 2010, $14.8 in 2011 and $121.2 in years 2012-2016.
Expected benefit payments projected to be required for postretirement benefits
during the years following 2006 (in millions) are $6.7 in 2007, $7.1 in 2008,
$7.5 in 2009, $8.0 in 2010, $8.3 in 2011 and $45.0 in years 2012-2016.
Benefit
Obligations
A
reconciliation of the Company’s benefit obligations at December 31, 2006, and
2005, follows:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2006
|
|
2005
|
||||||
|
Benefit
obligation, beginning of period
|
$
|
255.4
|
$
|
241.1
|
$
|
72.0
|
$
|
92.8
|
|||||
|
Service
cost – benefits earned during the period
|
6.0
|
5.6
|
0.6
|
0.7
|
|||||||||
|
Interest
cost on projected benefit obligation
|
14.1
|
13.8
|
3.9
|
4.5
|
|||||||||
|
Plan
participants' contributions
|
-
|
-
|
1.7
|
1.4
|
|||||||||
|
Plan
amendments
|
2.1
|
-
|
-
|
(21.7
|
)
|
||||||||
|
Actuarial
loss (gain)
|
(10.2
|
)
|
6.3
|
(0.4
|
)
|
2.0
|
|||||||
|
Medicare
subsidy receipts
|
-
|
-
|
0.3
|
-
|
|||||||||
|
Benefits
paid
|
(12.0
|
)
|
(11.4
|
)
|
(8.6
|
)
|
(7.7
|
)
|
|||||
|
Benefit
obligation, end of period
|
$
|
255.4
|
$
|
255.4
|
$
|
69.5
|
$
|
72.0
|
|||||
The
accumulated benefit obligation for all defined benefit pension plans was $234.8
million and $235.8 million at December 31, 2006, and 2005,
respectively.
The
benefit obligation as of December 31, 2006, and 2005, was calculated using
the
following weighted average assumptions:
|
|
|||||||||
|
Pension
Benefits
|
Other
Benefits
|
||||||||
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|||
|
Discount
rate
|
5.85%
|
5.50%
|
5.85%
|
5.50%
|
|||||
|
Rate
of compensation increase
|
3.75%
|
3.25%
|
3.75%
|
3.25%
|
|||||
|
Expected
increase in Consumer Price Index
|
N/A
|
N/A
|
3.50%
|
3.50%
|
|||||
To calculate the 2006 ending postretirement benefit obligation, medical claims costs in 2007 were assumed to be 9% higher than those incurred in 2006. That trend was assumed to gradually decline to 5% over a four year period and remain level thereafter. A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $1.3 million. To calculate the 2005 ending postretirement benefit obligation, medical claims costs in 2006 were assumed to be 10% higher than those incurred in 2005. That trend was assumed to gradually decline to 5% over a five year period and to remain level thereafter.
Plan
Assets
A
reconciliation of the Company’s plan assets at December 31, 2006, and 2005,
follows:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2006
|
|
2005
|
||||||
|
Plan
assets at fair value, beginning of period
|
$
|
173.6
|
$
|
161.2
|
$
|
7.4
|
$
|
8.3
|
|||||
|
Actual
return on plan assets
|
14.8
|
20.1
|
0.3
|
1.3
|
|||||||||
|
Employer
contributions
|
8.6
|
3.7
|
6.0
|
4.1
|
|||||||||
|
Plan
participants' contributions
|
-
|
-
|
1.7
|
1.4
|
|||||||||
|
Benefits
paid
|
(12.0
|
)
|
(11.4
|
)
|
(8.6
|
)
|
(7.7
|
)
|
|||||
|
Fair
value of plan assets, end of period
|
$
|
185.0
|
$
|
173.6
|
$
|
6.8
|
$
|
7.4
|
|||||
The
asset
allocation for the Company's pension and postretirement plans at the measurement
date for 2006 and 2005, by asset category, follows:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|||||||
|
Equity
securities
|
62
|
%
|
64
|
%
|
65
|
%
|
53
|
%
|
|||||
|
Debt
securities
|
33
|
%
|
33
|
%
|
31
|
%
|
37
|
%
|
|||||
|
Real
estate
|
5
|
%
|
3
|
%
|
-
|
-
|
|||||||
|
Short
term investments
|
-
|
-
|
4
|
%
|
10
|
%
|
|||||||
|
Total
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
|||||
The Company invests in a master trust that benefits its qualified defined benefit pension plans. The general investment objectives are to invest in a diversified portfolio, comprised of both equity and fixed income investments, which are further diversified among various asset classes. The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk. The investment objectives specify a targeted investment allocation for the pension plans of 60% equities, 35% debt, and 5% real estate for 2006, and for postretirement plans of 55% equities, 35% debt, and 10% short-term investments for 2006. Objectives do not target a specific return by asset class. The portfolio’s return is monitored in total and investment objectives are long-term in nature.
Funded
Status
The
funded status of the plans, reconciled to amounts reflected in the balance
sheets prior to the adoption of SFAS 158 in 2006 and as of December 31, 2005
follows:
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2006
|
|
2005
|
||||||
|
Fair
value of plan assets, end of period
|
$
|
185.0
|
$
|
173.6
|
$
|
6.8
|
$
|
7.4
|
|||||
|
Benefit
obligation, end of period
|
(255.4
|
)
|
(255.4
|
)
|
(69.5
|
)
|
(72.0
|
)
|
|||||
|
Funded
status, end of period
|
(70.4
|
)
|
(81.8
|
)
|
(62.7
|
)
|
(64.6
|
)
|
|||||
|
Unrecognized
net loss (gain)
|
35.3
|
48.6
|
(2.2
|
)
|
(2.0
|
)
|
|||||||
|
Unrecognized
prior service cost
|
12.9
|
12.6
|
(5.5
|
)
|
(6.3
|
)
|
|||||||
|
Unrecognized
transitional (asset) obligation
|
-
|
-
|
8.7
|
9.9
|
|||||||||
|
Post
measurement date adjustments
|
1.2
|
1.0
|
1.1
|
1.2
|
|||||||||
|
Net
amount recognized, prior to adoption of SFAS 158
|
$
|
(21.0
|
)
|
$
|
(19.6
|
)
|
$
|
(60.6
|
)
|
$
|
(61.8
|
)
|
|
Prior
to
the adoption of SFAS 158 in 2006 and as of December 31, 2005, the funded status
of the SERP, which is included in Pension Benefits in the chart above, was
an
unfunded amount of $13.4 million and $14.4 million, respectively.
Prior
to
the adoption of SFAS 158 in 2006 and as of December 31, 2005, substantially
all
pension and postretirement plans had accumulated benefit obligations in excess
of plan assets. As required by SFAS 87, the Company recorded an additional
minimum pension liability adjustment to reflect the total unfunded accumulated
liability arising from its pension plans. This additional minimum pension
liability adjustment is included in Deferred
credits & other liabilities.
The
offset to this additional liability was recorded to an intangible asset included
in Other
assets
to the
extent pension plans have unrecognized prior service cost. Any unfunded or
unaccrued amount in excess of prior service cost was recorded net of tax
in
Accumulated other comprehensive income
in
shareholders’ equity.
The
effects of additional minimum pension liability adjustments prior to the
adoption of SFAS 158 in 2006 and as of December 31, 2005
follow:
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Minimum
pension liability adjustment, beginning of year
|
$
|
(41.6
|
)
|
$
|
(43.5
|
)
|
|
|
Change
in minimum pension liability adjustment included in:
|
|||||||
|
Other
comprehensive income before effect of taxes
|
13.4
|
(0.3
|
)
|
||||
|
Other
assets
|
-
|
2.2
|
|||||
|
Minimum
pension liability adjustment, prior to adoption of SFAS
158
|
$
|
(28.2
|
)
|
$
|
(41.6
|
)
|
|
| 8. |
Borrowing
Arrangements
|
Long-Term
Debt
Long-term
senior unsecured obligations and first mortgage bonds outstanding by subsidiary
follow:
|
At
December 31,
|
||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|||||||
|
Utility
Holdings
|
||||||||||
| Fixed Rate Senior Unsecured Notes | ||||||||||
|
2011,
6.625%
|
$
|
250.0
|
$
|
250.0
|
||||||
|
2013,
5.25%
|
100.0
|
100.0
|
||||||||
|
2015,
5.45%
|
75.0
|
75.0
|
||||||||
|
2018,
5.75%
|
100.0
|
100.0
|
||||||||
|
2031,
7.25%
|
-
|
100.0
|
||||||||
|
2035,
6.10%
|
75.0
|
75.0
|
||||||||
|
2036,
5.95%
|
100.0
|
-
|
||||||||
|
Total
Utility Holdings
|
700.0
|
700.0
|
||||||||
|
SIGECO
|
||||||||||
|
First
Mortgage Bonds
|
||||||||||
|
2016,
1986 Series, 8.875%
|
13.0
|
13.0
|
||||||||
|
2020,
1998 Pollution Control Series B, 4.50%, tax exempt
|
4.6
|
4.6
|
||||||||
|
2024,
2000 Environmental Improvement Series A, 4.65%, tax exempt
|
22.5
|
22.5
|
||||||||
|
2029,
1999 Senior Notes, 6.72%
|
80.0
|
80.0
|
||||||||
|
2030,
1998 Pollution Control Series B, 5.00%, tax exempt
|
22.0
|
22.0
|
||||||||
|
2015,
1985 Pollution Control Series A, current adjustable rate 4.06%,
tax
exempt,
|
||||||||||
|
auction
rate mode, 2006 weighted average: 3.53%
|
9.8
|
9.8
|
||||||||
|
2023,
1993 Environmental Improvement Series B, current adjustable rate
4.11%,
|
||||||||||
|
tax
exempt, auction rate mode, 2006 weighted average: 3.74%
|
22.6
|
22.6
|
||||||||
|
2025,
1998 Pollution Control Series A, current adjustable rate 4.11%,
tax
exempt,
|
||||||||||
|
auction
rate mode, 2006 weighted average: 3.08%
|
31.5
|
31.5
|
||||||||
|
2030,
1998 Pollution Control Series C, current adjustable rate 4.11%,
tax
exempt,
|
||||||||||
|
auction
rate mode, 2006 weighted average: 3.20%
|
22.2
|
22.2
|
||||||||
|
Total
SIGECO
|
228.2
|
228.2
|
||||||||
|
At
December 31,
|
|||||
|
(In
millions)
|
2006
|
|
2005
|
||
|
Indiana
Gas
|
||||||||||
| Senior Unsecured Notes | ||||||||||
|
2007,
Series E, 6.54%
|
6.5
|
6.5
|
||||||||
|
2013,
Series E, 6.69%
|
5.0
|
5.0
|
||||||||
|
2015,
Series E, 7.15%
|
5.0
|
5.0
|
||||||||
|
2015,
Series E, 6.69%
|
5.0
|
5.0
|
||||||||
|
2015,
Series E, 6.69%
|
10.0
|
10.0
|
||||||||
|
2025,
Series E, 6.53%
|
10.0
|
10.0
|
||||||||
|
2027,
Series E, 6.42%
|
5.0
|
5.0
|
||||||||
|
2027,
Series E, 6.68%
|
1.0
|
1.0
|
||||||||
|
2027,
Series F, 6.34%
|
20.0
|
20.0
|
||||||||
|
2028,
Series F, 6.36%
|
10.0
|
10.0
|
||||||||
|
2028,
Series F, 6.55%
|
20.0
|
20.0
|
||||||||
|
2029,
Series G, 7.08%
|
30.0
|
30.0
|
||||||||
|
Total
Indiana Gas
|
127.5
|
127.5
|
||||||||
|
Vectren
Capital Corp.
|
||||||||||
|
Fixed
Rate Senior Unsecured Notes
|
||||||||||
|
2007,
7.83%
|
17.5
|
17.5
|
||||||||
|
2010,
4.99%
|
25.0
|
25.0
|
||||||||
|
2010,
7.98%
|
22.5
|
22.5
|
||||||||
|
2012,
5.13%
|
25.0
|
25.0
|
||||||||
|
2012,
7.43%
|
35.0
|
35.0
|
||||||||
|
2015,
5.31%
|
75.0
|
75.0
|
||||||||
|
Total
Vectren Capital Corp.
|
200.0
|
200.0
|
||||||||
|
Other
Long-Term Notes Payable
|
0.6
|
1.2
|
||||||||
|
Total
long-term debt outstanding
|
1,256.3
|
1,256.9
|
||||||||
|
Current
maturities of long-term debt
|
(24.2
|
)
|
(0.4
|
)
|
||||||
|
Debt
subject to tender
|
(20.0
|
)
|
(53.7
|
)
|
||||||
|
Unamortized
debt premium & discount - net
|
(3.8
|
)
|
(4.4
|
)
|
||||||
|
Fair
value of hedging arrangements
|
(0.3
|
)
|
(0.4
|
)
|
||||||
|
Total
long-term debt-net
|
$
|
1,208.0
|
$
|
1,198.0
|
||||||
Utility
Holdings 2006 Issuance
In
October 2006, Utility Holdings issued $100 million in 5.95% senior unsecured
notes due October 1, 2036 (2036 Notes). The 30-year notes were priced at par.
The 2036 Notes are guaranteed by Utility Holdings’ three public utilities:
SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional
and
joint and several. These
notes, as well as the timely payment of principal and interest, are insured
by a
financial guaranty insurance policy by Financial Guaranty Insurance Company
(FGIC).
The
2036
Notes have no sinking fund requirements, and interest payments are due
quarterly. The notes may be called by Utility Holdings, in whole or in part,
at
any time on or after October 1, 2011, at 100% of principal amount plus accrued
interest. During the first and second quarters of 2006, Utility Holdings entered
into several interest rate hedges with a $100 million notional amount. Upon
issuance of the notes, these instruments were settled resulting in the payment
of approximately $3.3 million, which was recorded as a Regulatory
asset
pursuant
to existing regulatory orders. The value paid is being amortized as an increase
to interest expense over the life of the issue.
The
proceeds from the sale of the 2036 Notes, settlement of the hedging
arrangements, and payments of issuance costs totaled approximately $92.8
million.
Utility
Holdings 2005 Issuance
In
December 2005, Utility Holdings issued senior unsecured notes with an aggregate
principal amount of $150 million in two $75 million tranches. The first tranche
was 10-year notes due December 2015, with an interest rate of 5.45% priced
at
99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year
notes due December 2035 with an interest rate of 6.10% priced at 99.799% to
yield 6.11% to maturity (2035 Notes).
The
notes
have no sinking fund requirements, and interest payments are due semi-annually.
The notes may be called by Utility Holdings, in whole or in part, at any time
for an amount equal to accrued and unpaid interest, plus the greater of 100%
of
the principal amount or the sum of the present values of the remaining scheduled
payments of principal and interest, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20
basis points for the 2015 Notes and 25 basis points for the 2035
Notes.
In
January and June 2005, Utility Holdings entered into forward starting interest
rate swaps with a total notional amount of $75 million. Upon issuance of the
debt, the instruments were settled resulting in the receipt of approximately
$1.9 million in cash, which was recorded as a regulatory liability pursuant
to
existing regulatory orders. The value received is being amortized as a reduction
of interest expense over the life of the issue maturing December 2035.
The
net
proceeds from the sale of the senior notes and settlement of related hedging
arrangements approximated $150
million.
Vectren
Capital Corp. 2005 Debt Issuance
On
October 11, 2005, Vectren and Vectren Capital Corp., its wholly-owned subsidiary
(Vectren Capital), entered into a private placement Note Purchase Agreement
(2005 Note Purchase Agreement) pursuant to which various institutional investors
purchased the following tranches of notes from Vectren Capital: (i) $25 million
4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13%
Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31%
Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes are
unconditionally guaranteed by Vectren, the parent of Vectren Capital. The
proceeds from this financing were received on December 15, 2005. This Note
Purchase Agreement contains customary representations, warranties and covenants,
including a covenant to the effect that the ratio of consolidated total debt
to
consolidated total capitalization will not exceed 75%.
On
October 11, 2005, Vectren and Vectren Capital entered into First Amendments
with
respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant
to
which Vectren Capital issued to institutional investors the following tranches
of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83%
Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and
(iv)
a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren
Capital issued to an institutional investor a $35 million 7.43% Senior Note
due
2012. The First Amendments (i) conform the covenants to those contained in
the
2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which
would have afforded noteholders the option to require prepayment if the ratings
of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the
unconditional guarantee by Vectren of the notes for the more limited support
agreement previously in place and (iv) provide for a 100 basis point increase
in
interest rates if the ratio of consolidated total debt to total capitalization
exceeds 65%.
Long-Term
Debt Put & Call Provisions
Certain
long-term debt issues contain put and call provisions that can be exercised
on
various dates before maturity. The put or call provisions are not triggered
by
specific events, but are based upon dates stated in the note agreements, such
as
when notes are remarketed. During 2006 and 2005, no debt was put to the Company.
During 2004 debt totaling $2.5 million was put to the Company. Debt which may
be
put to the Company during the years following 2006 (in millions) is $20.0 in
2007, zero in 2008, $80.0 in 2009, $10.0 in 2010, $30.0 in 2011, and zero
thereafter. Debt that may be put to the Company within one year is classified
as
Long-term
debt subject to tender
in
current liabilities.
Utility
Holdings, SIGECO and Indiana Gas Debt Calls
In
2006,
the Company called at par $100.0 million of Utility Holdings senior unsecured
notes originally due in 2031. In 2005, the Company called at par $49.9 million
of Indiana Gas insured quarterly senior unsecured notes originally due in 2030,
and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior
unsecured notes originally due in 2015. The notes called in 2006, 2005 and
2004
had stated interest rates of 7.25%, 7.45% and 7.15%, respectively.
Other
Financing Transactions
At
December 31, 2005, $53.7 million of SIGECO notes could be put to the Company
in
March of 2006, the date of their next remarketing. In March of 2006, the notes
were successfully remarketed, and are now classified in Long-term
debt. Prior
to
the remarketing, the notes had tax-exempt interest rates ranging from 4.75%
to
5.00%. After the remarketing, interest rates are reset every seven days using
an
auction process.
During
2004, the Company remarketed two first mortgage bonds outstanding at SIGECO.
The
remarketing effort converted $32.8 million of outstanding fixed rate debt into
variable rate debt where interest rates reset weekly. One bond, due in 2023,
had
a principal amount of $22.8 million and an interest rate of 6%. The other bond,
due in 2015, had a principal amount of $10.0 million and an interest rate of
4.3%. These remarketing efforts resulted in the extinguishment of debt and
the
reissuance of new debt at generally the same par value. These bonds are
classified in Long-term
debt.
As
part
of the integration of Miller into the Company’s consolidated financing model,
$24.0 million of Miller’s outstanding long-term debt was retired in the fourth
quarter of 2006.
Other
Company debt totaling $38.0 million in 2005, and $15.0 million in 2004 was
retired as scheduled.
Future
Long-Term Debt Sinking Fund Requirements & Maturities
The
annual sinking fund requirement of SIGECO's first mortgage bonds is 1% of the
greatest amount of bonds outstanding under the Mortgage Indenture. This
requirement may be satisfied by certification to the Trustee of unfunded
property additions in the prescribed amount as provided in the Mortgage
Indenture. SIGECO intends to meet the 2007 sinking fund requirement by this
means and, accordingly, the sinking fund requirement for 2007 is excluded from
Current
liabilities
in the
Consolidated Balance Sheets. At December 31, 2006, $739.1 million of SIGECO's
utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s
gross utility plant balance subject to the Mortgage Indenture approximated
$2.0
billion at December 31, 2006.
Consolidated
maturities of long-term debt during the five years following 2006 (in millions)
are $24.0 in 2007, zero in 2008 and in 2009, $47.5 in 2010, and $250.0 in
2011.
Short-Term
Borrowings
At
December 31, 2006, the Company has $794.0 million of short-term borrowing
capacity, including $520.0 million for the Utility Group operations and $274.0
million for the wholly owned Nonutility Group and corporate operations, of
which
approximately $250.0 million is available for the Utility Group operations
and
approximately $79.0 million is available for wholly owned Nonutility Group
and
corporate operations. These primarily short-term borrowing arrangements expire
in 2010. Utility Group credit facilities are primarily used to support the
Company’s access to the commercial paper market. Interest rates and outstanding
balances associated with short-term borrowing arrangements follows.
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|||||
|
Weighted
average commercial paper and bank loans
|
||||||||||
|
outstanding
during the year
|
$
|
256.1
|
$
|
304.5
|
$
|
211.4
|
||||
|
Weighted
average interest rates during the year
|
||||||||||
|
Commercial
paper
|
5.16
|
%
|
3.42
|
%
|
1.78
|
%
|
||||
|
Bank
loans
|
5.51
|
%
|
3.82
|
%
|
2.12
|
%
|
||||
|
At
December 31,
|
||||||||||
|
(In
millions)
|
2006
|
2005
|
||||||||
|
Commercial
paper
|
$
|
270.1
|
$
|
226.9
|
||||||
|
Bank
loans
|
194.7
|
73.0
|
||||||||
|
Total
short-term borrowings
|
$
|
464.8
|
$
|
299.9
|
||||||
During
2005, the Company increased the capacity of its utility-related credit
facilities by approximately $165 million in response to increased natural gas
costs.
Covenants
Both
long-term and short-term borrowing arrangements contain customary default
provisions; restrictions on liens, sale-leaseback transactions, mergers or
consolidations, and sales of assets; and restrictions on leverage and interest
coverage, among other restrictions. As of December 31, 2006, the Company was
in
compliance with all financial covenants.
Ratings
Triggers
None
of
Vectren’s currently outstanding debt arrangements contain ratings
triggers.
Debt
Guarantees
Vectren
Corporation guarantees Vectren Capital’s long-term and short-term debt, which
totaled $200.0 million and $194.7 million, respectively, at December 31, 2006.
Utility Holdings’ currently outstanding long-term and short-term debt is jointly
and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’
long-term and short-term debt outstanding at December 31, 2006, totaled $700.0
million and $270.1 million, respectively.
| 9. |
Share-Based
Compensation and Adoption of SFAS
123R
|
The
Company has various share-based compensation programs to encourage executives,
key non-officer employees, and non-employee directors to remain with the Company
and to more closely align their interests with those of the Company’s
shareholders. Under these programs, the Company issues stock options and
non-vested shares (herein referred to as restricted stock). All share-based
compensation programs are shareholder approved. In addition, the Company
maintains a deferred compensation plan for executives and non-employee directors
where participants have the option to invest earned compensation and vested
restricted stock in phantom stock units. Certain option and share awards provide
for accelerated vesting if there is a change in control or upon the
participant’s retirement.
On
January 1, 2006, the Company adopted SFAS 123R “Share Based Compensation” (SFAS
123R) using the modified prospective method. Accordingly, information prior
to
the adoption has not been restated. Prior to the adoption of SFAS 123R, the
Company accounted for these programs using APB Opinion 25, “Accounting for Stock
Issued to Employees” (APB 25), and its related interpretations. From the
Company’s perspective, the primary cost recognition difference between SFAS 123R
and APB 25 is that costs related to stock options were not recognized in the
financial statements in those years prior to SFAS 123R’s adoption.
Following
is a reconciliation of the total cost associated with share-based awards
recognized in the Company’s financial statements to its after tax effect on net
income:
|
Year
Ended December 31,
|
||||||||||
|
(in
millions)
|
2006
|
|
2005
|
|
2004
|
|||||
|
Total
cost of share-based compensation
|
$
|
3.2
|
$
|
4.5
|
$
|
4.0
|
||||
|
Less
capitalized cost
|
0.9
|
1.0
|
1.1
|
|||||||
|
Total
in other operating expense
|
2.3
|
3.5
|
2.9
|
|||||||
|
Less
income tax benefit in earnings
|
0.6
|
1.4
|
1.2
|
|||||||
|
After
tax effect of share-based compensation
|
$
|
1.7
|
$
|
2.1
|
$
|
1.7
|
||||
Restricted Stock Related Matters
The
Company periodically grants executives and other key non-officer employees
restricted stock whose vesting is contingent upon meeting a total return and/or
return on equity performance objectives. In addition non-employee
directors receive a portion of their fees in restricted stock. Grants to
executives and key non-officer employees generally vest at the end of a
four-year period, with performance measured at the end of the third year. Based
on that performance, awards could double or could be entirely forfeited. Awards
to non-employee directors are not performance based and generally vest over
one
year. Because executives and non-employee directors have the choice of settling
vested restricted stock awards in shares or deferring their receipt into a
deferred compensation plan (where the value is eventually withdrawn in cash),
these awards are accounted for as liability awards at their settlement date
fair
value. Upon adoption of SFAS 123R, the Company reclassified the earned value
of
these awards, which totaled $4.1 million on January 1, 2006, from equity to
other long-term liabilities. Awards to key non-officer employees must be settled
in shares and are therefore accounted for in equity at their grant date fair
value.
A
summary
of the status of the Company’s restricted stock awards separated between those
accounted for as liabilities and equity as of December 31, 2006, and changes
during the twelve months ended December 31, 2006, is presented
below:
|
Equity
Awards
|
Liability
Awards
|
||||||||||||
|
|
Wtd.
Avg.
|
|
|
||||||||||
|
|
|
Grant
Date
|
|
Wtd.
Avg.
|
|||||||||
|
|
Shares
|
Fair
value
|
Shares
|
Fair
value
|
|||||||||
|
Restricted
at January 1, 2006
|
17,369
|
$
|
26.42
|
336,216
|
$
|
27.16
|
|||||||
|
Granted
|
10,690
|
26.60
|
185,027
|
27.54
|
|||||||||
|
Vested
|
(84
|
)
|
27.62
|
(68,235
|
)
|
26.60
|
|||||||
|
Forfeited
|
(4,966
|
)
|
27.24
|
(76,823
|
)
|
24.46
|
|||||||
|
Restricted
at December 31, 2006
|
23,009
|
$
|
26.32
|
376,185
|
$
|
28.28
|
|||||||
As
of
December 31, 2006, there was $6.2 million of total unrecognized compensation
cost related to restricted stock awards. That cost is expected to be
recognized over a weighted-average period of 2.1 years. The total fair
value of shares vested for awards to executives and non-employee directors
(Liability Awards) during the years ended December 31, 2006, 2005, and 2004,
was
$1.8 million, $2.1 million, and $2.0 million, respectively. On
January 1, 2007, 167,100 awards that will be accounted for as liabilities were
granted to officers of the Company.
Stock
Option Related Matters
Option
awards are generally granted to executives with an exercise price equal to
the
market price of the Company’s stock at the date of grant; those option awards
generally require 3 years of continuous service and have 10-year contractual
terms. Share awards generally vest on a pro-rata basis over 3 years. No options
were granted in 2006, and the Company does not intend to issue options in
2007.
The
fair
value of option awards granted in prior years was estimated on the date of
grant
using a Black-Scholes option valuation model that used the assumptions noted
below. Expected volatilities were based on historical volatility of the
Company’s stock and other factors. The Company used historical data to
estimate the expected term and forfeiture patterns of the options. The
risk-free rate for periods within the contractual life of the option was based
on the U.S. Treasury yield curve in effect at the time of grant. The
fair
value of each option granted used to determine pro forma net income as disclosed
in Note 2, was estimated as of the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions used for grants
in
the years ended December 31, 2005 and 2004: risk-free rate of return of 4.22%
and 4.37%, respectively; expected option term of 8 years for both years;
expected volatility of 21.43% and 24.01%, respectively; and dividend yield
of
4.4% and 4.65%, respectively. The weighted average fair value of options granted
in 2005 and 2004 were $4.36 and $4.39, respectively.
A
summary
of the status of the Company’s stock option awards as of December 31, 2006, and
changes during the period ended December 31, 2006, follows:
|
Weighted
average
|
|
Aggregate
|
|
||||||||||
|
|
|
|
|
|
|
Remaining
|
|
Intrinsic
|
|
||||
|
|
|
Shares
|
|
Exercise
|
|
Contractual
|
|
Value
|
|
||||
|
|
|
|
|
Price
|
|
Term
(years)
|
|
(In
millions)
|
|||||
|
Outstanding
at January 1, 2006
|
2,123,579
|
$
|
23.18
|
||||||||||
|
Granted
|
-
|
-
|
|||||||||||
|
Exercised
|
149,948
|
$
|
21.39
|
||||||||||
|
Forfeited
or expired
|
9,646
|
$
|
21.09
|
||||||||||
|
Outstanding
at December 31, 2006
|
1,963,985
|
$
|
23.33
|
5.3
|
$
|
9.7
|
|||||||
|
Exercisable
at December 31, 2006
|
1,696,803
|
$
|
22.89
|
4.9
|
$
|
9.1
|
|||||||
The
total
intrinsic value of options exercised during the twelve months ended December
31,
2006, 2005, and 2004 was $0.8 million, $1.6 million, and $2.6 million,
respectively. As of December 31, 2006, there was less than $0.1 million of
total
unrecognized compensation cost related to vesting stock options. That cost
is
expected to be recognized over a weighted-average period of less than 1.0 year.
The actual tax benefit realized for tax deductions from option exercises was
approximately $0.2 million in 2006, $0.1 million in 2005, and $0.3 million
in
2004.
The
Company periodically issues new shares and also from time to time repurchases
shares on the open market to satisfy share option exercises. During the twelve
months ended December 31, 2006, 2005, and 2004, the Company received value
upon
exercise of stock options totaling approximately $3.2 million, $1.6 million,
and
$1.7 million, respectively. During those periods, the Company repurchased shares
totaling $3.8 million in 2006 and $2.1 million in 2005. No shares were purchased
on the open market in 2004. The Company does not expect future period repurchase
activity to be materially different.
Deferred
Compensation Plan Matters
As
discussed above, the Company has nonqualified deferred compensation plans that
include an option to invest in Company phantom stock. The amount recorded in
earnings related to the investment activities in Vectren phantom stock
associated with these plans during the years ended December 31, 2006, 2005
and
2004, was a benefit of $0.3 million, and a cost of $1.5 million and $0.7
million, respectively.
| 10. |
Common
Shareholders’ Equity
|
Authorized,
Reserved Common and Preferred Shares
At
December 31, 2006, and 2005, the Company was authorized to issue 480.0 million
shares of common stock and 20.0 million shares of preferred stock. Of the
authorized common shares, approximately 7.2 million shares at December 31,
2006,
and 6.4 million shares at December 31, 2005, were reserved by the board of
directors for issuance through the Company’s share-based compensation plans,
benefit plans, and dividend reinvestment plan. At December 31, 2006, and 2005,
there were 396.7 million and 397.6 million, respectively, of authorized shares
of common stock and all authorized shares of preferred stock, available for
a
variety of general corporate purposes, including future public offerings to
raise additional capital and for facilitating acquisitions.
Shareholder
Rights Agreement
The
Company’s board of directors previously adopted a Shareholder Rights Agreement
(Rights Agreement). As part of the Rights Agreement, the board of directors
declared a dividend distribution of one right for each outstanding Vectren
common share. Each right entitles the holder to purchase from Vectren one share
of common stock at a price of $65.00 per share (subject to adjustment to prevent
dilution). The rights become exercisable 10 days following a public announcement
that a person or group of affiliated or associated persons (Vectren Acquiring
Person) has acquired beneficial ownership of 15% or more of the outstanding
Vectren common shares (or a 10% acquirer who is determined by the board of
directors to be an adverse person), or 10 days following the announcement of
an
intention to make a tender offer or exchange offer, the consummation of which
would result in any person or group becoming a Vectren Acquiring Person. The
Vectren Shareholder Rights Agreement expires October 21, 2009.
| 11. |
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 using the treasury stock method and the conversion of restricted
shares into unrestricted shares using the contingently issuable share method
to
the extent the effect would be dilutive.
The
following table illustrates the basic and dilutive earnings per share
calculations for the three years ended December 31, 2006:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions, except per share data)
|
2006
|
|
2005
|
|
2004
|
|||||
|
Numerator:
|
||||||||||
|
Numerator
for basic and diluted EPS - Net income
|
$
|
108.8
|
$
|
136.8
|
$
|
107.9
|
||||
|
Denominator:
|
||||||||||
|
Denominator
for basic EPS - Weighted average
|
||||||||||
|
common
shares outstanding
|
75.7
|
75.6
|
75.6
|
|||||||
|
Conversion
of stock options and lifting of
|
||||||||||
|
restrictions
on issued restricted stock
|
0.5
|
0.5
|
0.3
|
|||||||
|
Denominator
for diluted EPS - Adjusted weighted
|
||||||||||
|
average
shares outstanding and assumed
|
||||||||||
|
conversions
outstanding
|
76.2
|
76.1
|
75.9
|
|||||||
|
Basic
earnings per share
|
$
|
1.44
|
$
|
1.81
|
$
|
1.43
|
||||
|
Diluted
earnings per share
|
$
|
1.43
|
$
|
1.80
|
$
|
1.42
|
||||
Options to purchase 4,200 shares of common stock for the year ended December 31, 2004 were excluded in the computation of dilutive earnings per share because the options’ exercise price was greater than the average market price of a share of common stock during the period. The exercise price for options excluded from the computation was $25.59 in 2004. For the year ended December 31, 2006 and 2005, all options were dilutive.
| 12. |
Commitments
& Contingencies
|
Commitments
Future
minimum lease payments required under operating leases that have initial or
remaining noncancelable lease terms in excess of one year during the five years
following 2006 and thereafter (in millions) are $7.7 in 2007, $4.6 in 2008,
$2.6
in 2009, $1.5 in 2010, $0.9 in 2011, and $1.0 thereafter. Total lease expense
(in millions) was $8.5 in 2006, $6.1 in 2005, and $6.7 in 2004.
Firm
purchase commitments for commodities by consolidated companies total (in
millions) $96.7 million in 2007, $21.4 million in 2008, $3.3 million in 2009,
$2.9 million in 2010, and zero in 2011 and thereafter. Firm purchase commitments
for utility and nonutility plant total (in millions) $66.4 million in 2007,
$113.0 million in 2008, $115.0 million in 2009, $70.0 million in 2010, and
$28.0
million in 2011.
Other
Guarantees
Vectren
issues guarantees to third parties on behalf of its unconsolidated affiliates.
Such guarantees allow those affiliates to execute transactions on more favorable
terms than the affiliate could obtain without such a guarantee. Guarantees
may
include posted letters of credit, leasing guarantees, and performance
guarantees. As of December 31, 2006, guarantees issued and outstanding on behalf
of unconsolidated affiliates approximated $3.0 million. The Company has accrued
no liabilities for these guarantees as they relate to guarantees issued among
related parties, or such guarantees were executed prior to the adoption of
FASB
Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others.”
In
2006,
the Company issued a guarantee with an approximate $5 million maximum risk
related to the residual value of an operating lease that expires in 2011. As
of
December 31, 2006, Vectren Corporation has a liability representing the fair
value of that guarantee of approximately $0.1 million. Liabilities accrued
for,
and activity related to, product warranties are not significant.
Legal
Proceedings
The
Company is party to various legal proceedings arising in the normal course
of
business. In the opinion of management, there are no legal proceedings pending
against the Company that are likely to have a material adverse effect on its
financial position, results of operations or cash flows.
| 13. |
Environmental
Matters
|
Clean
Air Act
Clean
Air Interstate Rule & Clean Air Mercury Rule
In
March
of 2005 USEPA finalized two new air emission reduction regulations. The
Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring
further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2)
emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR)
is
an allowance cap and trade program requiring further reductions in mercury
emissions from coal-burning power plants. Both sets of regulations require
emission reductions in two phases. The first phase deadline for both rules
is
2010 (2009 for NOx under CAIR), and the second phase deadline for compliance
with the emission reductions required under CAIR is 2015, while the second
phase
deadline for compliance with the emission reduction requirements of CAMR is
2018. The Company is evaluating compliance options and fully expects to be
in
compliance by the required deadlines.
In
February 2006, the IURC approved a multi-emission compliance plan filed by
the
Company’s utility subsidiary, SIGECO. Once the plan is implemented, SIGECO’s
coal-fired plants will be 100% scrubbed for SO2,
90%
scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury
reduction standards. The order, as previously agreed to by the OUCC and Citizens
Action Coalition, allows SIGECO to recover an approximate 8% return on up to
$110 million in capital investments through a rider mechanism which is updated
every six months for actual costs incurred. The Company will also recover
through a rider its operating expenses, including depreciation, once the
equipment is placed into service. The order also stipulates that SIGECO study
renewable energy alternatives and include a carbon forecast in future filings
with regard to new generation and further environmental compliance plans, among
other initiatives. As of December 31, 2006, the Company has made capital
investments of approximately $62.2 million related to this environmental
requirement.
NOx
SIP Call Matter
The
Company complied with Indiana’s State Implementation Plan (SIP) of the Clean Air
Act (the Act). These steps included installation 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 currently be the most effective
method of reducing nitrogen oxide (NOx) emissions where high removal
efficiencies are required.
The
IURC
issued orders that approved:
| · |
the
Company’s project to achieve environmental compliance by investing in
clean coal technology;
|
| · |
the
Company’s investment of $258 million in capital
costs;
|
| · |
a
mechanism whereby, prior to an electric base rate case, the Company
recovers through a rider that is updated every six months, an 8%
return on
its weighted capital costs for the project; and
|
| · |
ongoing
recovery of operating costs, including depreciation and purchased
emission
allowances, related to the clean coal technology now that facilities
are
placed into service.
|
Culley
Generating Station Litigation
During
2003, the U.S. District Court for the Southern District of Indiana entered
a
consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA
that
resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit
alleged violations of the Clean Air Act by SIGECO at its Culley Generating
Station for (1) making modifications to a generating station without obtaining
required permits, (2) making major modifications to the generating station
without installing the best available emission control technology, and (3)
failing to notify the USEPA of the modifications.
Under
the
terms of the agreement, the DOJ and USEPA agreed to drop all challenges of
past
maintenance and repair activities at the Culley Generating Station. In reaching
the agreement, SIGECO did not admit to any allegations in the government’s
complaint, and SIGECO continues to believe that it acted in accordance with
applicable regulations and conducted only routine maintenance on the units.
SIGECO entered into this agreement to further its continued commitment to
improve air quality and avoid the cost and uncertainties of litigation.
Under
the
agreement, SIGECO committed to:
| · |
either
repower Culley Unit 1 (50 MW) with natural gas and equip it with
SCR
control technology for further reduction of nitrogen oxide, or cease
operation of the unit by December 31,
2006;
|
| · |
operate
the existing SCR control technology recently installed on Culley
Unit 3
(287 MW) year round at a lower emission rate than that currently
required
under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
|
| · |
enhance
the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide
emissions;
|
| · |
install
a baghouse for further particulate matter reductions at Culley Unit
3 by
June 30, 2007;
|
| · |
conduct
a Sulphuric Acid Reduction Demonstration Project as an environmental
mitigation project designed to demonstrate an advance in pollution
control
technology for the reduction of sulfate emissions; and
|
| · |
pay
a $600,000 civil penalty.
|
The
Company does not believe that implementation of the settlement will have a
material effect on its results of operations or financial condition. The
$600,000 civil penalty was expensed and paid during 2003. The Company ceased
operation of Culley Unit 1 effective December 31, 2006 and the baghouse, which
is included in the $110 million IURC order discussed above, went into service
January 1, 2007.
Manufactured
Gas Plants
In
the
past, Indiana Gas, SIGECO, 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, those that operated these facilities may
now
be required to take remedial action if certain byproducts are found above the
regulatory thresholds at these sites.
Indiana
Gas 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 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
(VRP)
and is currently conducting some level of remedial activities, including
groundwater monitoring at certain sites, where deemed appropriate, and will
continue remedial activities at the sites as appropriate and
necessary.
In
conjunction with data compiled by environmental consultants, Indiana Gas 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.
In
October 2002, SIGECO received a formal information request letter from the
IDEM
regarding five manufactured gas plants that it owned and/or operated and were
not enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the
results of preliminary site investigations conducted in the mid-1990’s. These
site investigations confirmed that based upon the conditions known at the time,
the sites posed no imminent and/or substantial risk to human health or the
environment.
On
October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas
plant sites in IDEM's VRP. The remaining site is currently being addressed
in
the VRP by another Indiana utility. SIGECO added those four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has
in
place with IDEM for its manufactured gas plant sites. That renewal was approved
by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory
judgment action against its insurance carriers seeking a judgment finding its
carriers liable under the policies for coverage of further investigation and
any
necessary remediation costs that SIGECO may accrue under the VRP program. While
the total costs that may be incurred in connection with addressing these sites
cannot be determined at this time, SIGECO has recorded costs that it reasonably
expects to incur totaling approximately $7.7 million. With respect to insurance
coverage, SIGECO has received and recorded settlements from insurance carriers
in an aggregate amount approximating the costs it expects to incur.
Environmental
matters related to Indiana Gas’ and SIGECO’s manufactured gas plants have had no
material impact on results of operations or financial condition since costs
recorded to date approximate PRP and insurance settlement recoveries. While
the
Company’s utilities have recorded all costs which they presently expect 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.
Jacobsville
Superfund Site
On
July
22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination
site
in Evansville, Indiana, on the National Priorities List under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA). The USEPA
has
identified four sources of historic lead contamination. These four sources
shut
down manufacturing operations years ago. When drawing up the boundaries for
the
listing, the USEPA included a 250 acre block of properties surrounding the
Jacobsville neighborhood, including Vectren's Wagner Operations Center.
Vectren's property has not been named as a source of the lead contamination,
nor
does the USEPA's soil testing to date indicate that the Vectren property
contains lead contaminated soils. Vectren's own soil testing, completed during
the construction of the Operations Center, did not indicate that the Vectren
property contains lead contaminated soils. At this time, Vectren anticipates
only additional soil testing, if required by the USEPA.
Global
Climate Change
Global
climate change remains a policy issue that is regularly considered for
government regulation. If legislation requiring reductions in greenhouses gases
is adopted, such regulation could substantially affect both the costs and
operating characteristics of the Company’s fossil fuel plants. Further, that
Company’s nonutility coal mining operations may be adversely
affected.
| 14. |
Rate
& Regulatory Matters
|
Ohio
and Indiana Lost Margin Recovery/Conservation Filings
In
2005,
the Company filed conservation programs and conservation adjustment trackers
in
Indiana and Ohio designed to help customers conserve energy and reduce their
annual gas bills. The programs would allow the Company to recover costs of
promoting the conservation of natural gas through conservation trackers that
work in tandem with a lost margin recovery mechanism. This mechanism is designed
to allow the Company to recover the distribution portion of its rates from
residential and commercial customers based on the level of customer revenues
established in each utility’s last general rate case.
Indiana
In
December 2006, the IURC approved a settlement agreement between the Company
and
the OUCC that provides for a 5-year energy efficiency program to be implemented.
The order allows the Company’s Indiana utilities to recover the costs of
promoting the conservation of natural gas through conservation trackers that
work in tandem with a lost margin recovery mechanism that would provide for
recovery of 85% of the difference between revenues actually collected by the
Company and the revenues approved in the Company’s most recent rate case. The
order was implemented in the North service territory in December 2006 and will
be implemented in South’s service territory after its next general rate case
(see below.) While most expenses associated with these programs are recoverable,
in the first program year, the Company is required to fund $1.5 million in
program costs without recovery.
Ohio
In
September 2006, the PUCO approved a conservation proposal that would implement
a
decoupling approach, including a related conservation program, for the Company’s
Ohio operations. The PUCO decision was issued following a hearing process and
the submission of a settlement by the Company, the Ohio Consumer Counselor
(OCC)
and the Ohio Partners for Affordable Energy (OPAE). That settlement was
contested by the PUCO Staff. In the decision the PUCO addressed decoupling
by
approving a two year, $2 million total, low-income conservation program to
be
funded by the Company, as well as a sales reconciliation rider intended to
be a
recovery mechanism for the difference between the weather normalized revenues
actually collected by the company and the revenues approved by the PUCO in
the
Company’s most recent rate case. The decision produced an outcome that was
different from the settlement. Following the decision, the Company and the
OPAE
advised the PUCO that they would accept the outcome even though it differed
from
the terms of the settlement. The OCC sought rehearing of the decision, which
was
denied in December, and thereafter the OCC advised the PUCO that the OCC was
withdrawing from the settlement. At that point the OCC also initiated the
process for appealing the PUCO’s September and December decisions to the Ohio
Supreme Court. Thereafter, the Company, the OPAE and the PUCO Staff advised
the
PUCO that they accepted the terms provided in the September decision, as
affirmed by the December rehearing decision. Since that time there have been
a
number of procedural filings by the parties and presently the company is
awaiting a further decision from the PUCO. The company believes that the PUCO
had the necessary legal basis for its decisions and thus should confirm the
outcome provided in the September decision.
Vectren
South (Southern Indiana Gas & Electric) Base Rate Filings
On
September 1, 2006, Vectren South filed petitions with the IURC to adjust its
electric and gas base rates in its South service territory. The electric
petition requests an increase of $76.7 million in base rates to recover the
nearly $120 million additional investment in electric utility infrastructure
since its last base rate increase in 1995, which is not currently included
in
rates charged to customers. The increase in rates also is required to support
system growth, maintenance, reliability and recovery of costs deferred under
previous IURC orders. The gas petition seeks to increase its gas base (non-gas
cost) rates by $10.4 million to cover the ongoing costs of operating and
maintaining its natural gas distribution and storage system. Based upon the
timelines prescribed by the IURC at the start of these proceedings, decisions
in
each case are expected to be issued in the late summer of 2007. The initial
public hearings in both cases have been conducted. On January 30, 2007, the
OUCC
filed testimony in the gas rate case proposing an increase of $5.1
million.
IGCC
Certificate of Public Convenience and Necessity
On
September 7, 2006, Vectren Energy Delivery of Indiana and Duke Energy Indiana,
Inc. filed with the IURC a joint petition for a Certificate of Public
Convenience and Necessity (CPCN) for the construction of new electric capacity.
Specifically, Vectren requested the IURC approve its construction and ownership
of up to 20% of an Integrated Gasification Combined Cycle (IGCC) project.
Vectren's CPCN filing also seeks timely recovery of its 20% portion of the
project's construction costs as well as operation and maintenance costs and
additional incentives available for the construction of clean coal technology.
Initial studies of plant design have already begun, and if the project moves
forward as currently designed, plant construction is expected to begin in 2007
and continue through 2011.
Weather
Normalization
On
October 5, 2005, the IURC approved the establishment of a normal temperature
adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The OUCC
had
previously entered into a settlement agreement with Vectren Energy Delivery
of
Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated
residential and commercial natural gas customers and should mitigate weather
risk in those customer classes during the October to April heating season.
These
Indiana customer classes represent approximately 60-65% of the Company’s total
natural gas heating load.
The
NTA
mechanism will mitigate volatility in distribution charges created by
fluctuations in weather by lowering customer bills when weather is colder than
normal and increasing customer bills when weather is warmer than normal. The
NTA
has been applied to meters read and bills rendered after October 15, 2005.
Each
subsequent monthly bill for the seven-month heating season will be adjusted
using the NTA.
The
order
provides that the Company will make, on a monthly basis, a commitment of
$125,000 to a universal service fund program or other low-income assistance
program for the duration of the NTA or until a general rate case.
Rate
structures in the Company’s Indiana electric territory and Ohio gas territory do
not include weather normalization-type clauses.
Gas
Utility Base Rate Settlements in 2004 and 2005
On
June
30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas
distribution business, and on November 30, 2004, approved a $24 million base
rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the
PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution
business. The base rate change in SIGECO’s service territory was implemented on
July 1, 2004; the base rate change in Indiana Gas’ service territory was
implemented on December 1, 2004; and the base rate change in VEDO’s service
territory was implemented on April 14, 2005.
The
orders also permit SIGECO and Indiana Gas to recover the on-going costs to
comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety
Improvement Tracker provides for the recovery of incremental non-capital
dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO
and $2.5 million per year for Indiana Gas. Any costs incurred in excess of
these
annual caps are to be deferred for future recovery. VEDO’s new base rates
provide for the recovery of some level of on-going costs to comply with the
Pipeline Safety Improvement Act of 2002.
MISO
Since
February 2002 and with the IURC’s approval, the Company has been a member of the
Midwest Independent System Operator, Inc. (MISO), a FERC approved regional
transmission organization. The MISO serves the electrical transmission needs
of
much of the Midwest and maintains operational control over the Company’s
electric transmission facilities as well as that of other Midwest utilities.
Pursuant to an order from the IURC received in December 2001, certain MISO
startup costs (referred to as Day 1 costs) have been deferred for future
recovery in the next general rate case, which was filed in 2006.
On
April
1, 2005, the MISO energy market commenced operation (the Day 2 energy market).
As a result of being a market participant, the Company now bids its owned
generation into the Day Ahead and Real Time markets and procures power for
its
retail customers at Locational Marginal Pricing (LMP) as determined by the
MISO
market.
On
June
1, 2005, Vectren, together with three other Indiana electric utilities, received
regulatory authority from the IURC that allows recovery of fuel related costs
and deferral of other costs associated with the Day 2 energy market. The order
allows fuel related costs to be passed through to customers in Vectren’s
existing fuel cost recovery proceedings. The other non-fuel and MISO
administrative related costs are to be deferred for recovery as part of the
next
electric general rate case proceeding, which was filed in 2006. During 2006,
the
IURC reaffirmed the definition of certain costs as fuel related; the company
is
following those guidelines.
As
a
result of MISO’s operational control over much of the Midwestern electric
transmission grid, including SIGECO’s transmission facilities, SIGECO’s
continued ability to import power, when necessary, and export power to the
wholesale market has been, and may continue to be, impacted. Given the nature
of
MISO’s policies regarding use of transmission facilities, as well as ongoing
FERC initiatives and uncertainties around Day 2 energy market operations, it
is
difficult to predict near term operational impacts. However, as stated above,
it
is believed that MISO’s regional operation of the transmission system will
ultimately lead to reliability improvements.
The
potential need to expend capital for improvements to the transmission system,
both to SIGECO’s facilities as well as to those facilities of adjacent
utilities, over the next several years will become more predictable as MISO
completes studies related to regional transmission planning and improvements.
Such expenditures may be significant.
Gas
Cost Recovery (GCR) Audit Proceedings
On
June
14, 2005, the PUCO issued an order disallowing the recovery of approximately
$9.6 million of gas costs relating to the two-year audit period ended November
2002. That audit period provided the PUCO staff its initial review of the
portfolio administration arrangement between VEDO and ProLiance. The
disallowance includes approximately $1.3 million relating to pipeline refunds
and penalties and approximately $4.5 million of costs for winter delivery
services purchased by VEDO to ensure reliability over the two-year period.
The
PUCO also held that ProLiance should have credited to VEDO an additional $3.8
million more than credits actually received for the right to use VEDO’s gas
transportation capacity periodically during the periods when it was not required
for serving VEDO’s customers. The PUCO also directed VEDO to either submit its
receipt of portfolio administration services to a request for proposal process
or to in-source those functions. During 2003, the Company recorded a reserve
of
$1.1 million for this matter. An additional pretax charge of $4.1 million was
recorded in
Cost
of gas sold
in 2005.
The reserve reflects management’s assessment of the impact of the PUCO
decisions, an estimate of any current impact that decision may have on
subsequent audit periods, and an estimate of a sharing in any final disallowance
by Vectren’s partner in ProLiance.
VEDO
filed its request for rehearing on July 14, 2005, and on August 10, 2005, the
PUCO granted rehearing to further consider the $3.8 million portfolio
administration issue and all interest on the findings, but denied rehearing
on
all other aspects of the case. On October 7, 2005, the Company filed an appeal
with the Ohio Supreme Court requesting that the $4.5 million disallowance
related to the winter delivery service issue be reversed. On December 21, 2005,
the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million
disallowance related to portfolio administration to $1.98 million. The Company
has appealed the $1.98 million disallowance to the Ohio Supreme Court as well.
Briefings of all matters and oral arguments were completed in November 2006,
and
the parties are awaiting the Court’s ruling.
With
respect to the most recent GCR audit covering the period of November 1, 2002
through October 31, 2005, the PUCO staff recommended a disallowance of
approximately $830,000 related solely to the retention of a reserve margin
for
the winter of 2002/2003. The Company had previously reserved for the possible
disallowance given the June 2005 PUCO order but has contested the disallowance.
The PUCO will issue a decision on that issue in 2007.
As
a
result of the June 2005 PUCO order, the Company has established an annual
bidding process for VEDO’s gas supply and portfolio administration services.
Since November 1, 2005, the Company has used a third party provider for these
services.
| 15. |
Derivatives
& Other Financial
Instruments
|
Accounting
Policy for Derivatives
The
Company executes derivative contracts in the normal course of operations while
buying and selling commodities to be used in operations, optimizing its
generation assets, and managing risk. The Company accounts for its derivative
contracts in accordance with SFAS 133, “Accounting for Derivatives” and its
related amendments and interpretations. In most cases, SFAS 133 requires a
derivative to be recorded on the balance sheet as an asset or liability measured
at its market value and that a change in the derivative's market value be
recognized currently in earnings unless specific hedge criteria are met.
When
an
energy contract that is a derivative is designated and documented as a normal
purchase or normal sale, it is exempted from mark-to-market accounting.
Otherwise, energy contracts and financial contracts that are derivatives are
recorded at market value as current or noncurrent assets or liabilities
depending on their value and on when the contracts are expected to be settled.
The offset resulting from carrying the derivative at fair value on the balance
sheet is charged to earnings unless it qualifies as a hedge or is subject to
SFAS 71. When hedge accounting is appropriate, the Company assesses and
documents hedging relationships between the derivative contract and underlying
risks as well as its risk management objectives and anticipated effectiveness.
When the hedging relationship is highly effective, derivatives are designated
as
hedges. The market value of the effective portion of the hedge is marked to
market in accumulated other comprehensive income for cash flow hedges or, as
an
adjustment to the underlying’s basis for fair value hedges. The ineffective
portion of hedging arrangements is marked-to-market through earnings. The offset
to contracts affected by SFAS 71 are marked-to-market as a regulatory asset
or
liability. Market value for derivative contracts is determined using quoted
market prices from independent sources. Following is a more detailed discussion
of the Company’s use of mark-to-market accounting in five primary areas: asset
optimization, synfuels hedging, SO2
emission
allowance risk management, natural gas procurement, and interest rate
management.
Asset
Optimization
Periodically,
generation capacity is in excess of that needed to serve native load and firm
wholesale customers. The Company markets this unutilized capacity to optimize
the return on its owned generation assets. These optimization strategies involve
the sale of excess generation into the MISO day ahead and real-time markets.
As
part of these strategies, the Company may execute energy contracts that are
integrated with portfolio requirements around power supply and delivery and
are
short-term purchase and sale transactions that expose the Company to limited
market risk. Contracts with counter-parties subject to master netting
arrangements are presented net in the Consolidated Balance Sheets. Asset
optimization contracts that are derivatives are recorded at market
value.
At
December 31, 2006, no asset optimization contracts remained in Prepayments
& other current assets.
At
December 31, 2005, asset optimization contracts recorded at market value
approximated $1.3 million of Prepayments
& other current assets.
The
proceeds received and paid upon settlement of both purchase and sale contracts
along with changes in market value of open contracts that
are
derivatives are
recorded in Electric
utility revenues.
Net
revenues from asset optimization activities totaled $29.8 million in 2006,
$38.0
million in 2005, and $23.8 million in 2004.
Synfuel
Risk Management
As
discussed in Note 3, the Company’s synfuel operations are exposed to commodity
price risk associated with oil. The Company has executed derivative instruments
designed to limit the effects of a phase out of synfuel tax credits. During
2006
the Company purchased contracts with a notional amount of 0.5 million barrels
to
mitigate 2006 phase out risk. All contracts were settled in 2006 at a loss
of
$5.3 million, which is recorded in Other-net.
In
2006, the Company also purchased contracts with a notional amount of 2.8 million
barrels to mitigate 2007 phase out risk. The mark to market loss associated
with
these contracts totaled $2.5 million in 2006 and is also reflected in
Other-net.
The
fair value of those contracts which is recorded in Prepayments
and other current assets totaled
$11.2 million as of December 31, 2006. The pretax impact of an insurance
contract related to synfuels was earnings of $3.1 million in 2006 and a loss
of
$1.9 million in 2005. These results are also recorded in Other,
net.
As of
December 31, 2006 and 2005, the fair value of the insurance contract, which
is
included in Prepayments
and other current assets, totaled
$4.4 million and $1.3 million, respectively.
SO2
Emission Allowance Risk Management
The
Company’s wholesale power marketing operations are exposed to price risk
associated with SO2
emission
allowances. Recently, the price for emission allowances has become more
volatile. To hedge this risk, the Company executed call options in 2004 and
2005
to hedge wholesale emission allowance utilization in future periods. The Company
designated and documented these derivatives as cash flow hedges. At December
31,
2006, a deferred gain of approximately $1.4 million remains in accumulated
comprehensive income which will be recognized in earnings as emission allowances
are utilized. Hedge ineffectiveness totaled $0.2 million of expense in 2006
and
$0.8 million of expense in 2005. No SO2
emission
allowance hedges are outstanding as of December 31, 2006.
Natural
Gas Procurement Activity
The
Company’s regulated operations have limited exposure to commodity price risk for
purchases and sales of natural gas and electricity for retail customers due
to
current Indiana and Ohio regulations which, subject to compliance with those
regulations, allow for recovery of such purchases through natural gas and fuel
cost adjustment mechanisms. Although Vectren’s regulated operations are exposed
to limited commodity price risk, volatile natural gas prices can result in
higher working capital requirements, increased expenses including unrecoverable
interest costs, uncollectible accounts expense, and unaccounted for gas, and
some level of price- sensitive reduction in volumes sold. The Company mitigates
these risks by executing derivative contracts that manage the price volatility
of forecasted natural gas purchases. These contracts are subject to regulation
which allows for reasonable and prudent hedging costs to be recovered through
rates. When regulation is involved, SFAS 71 controls when the offset to
mark-to-market accounting is recognized in earnings.
The
Company’s wholly owned gas retail operations also mitigate price risk associated
with forecasted natural gas purchases by using derivatives. These nonregulated
gas retail operations may also from time-to-time execute weather derivatives
to
mitigate extreme weather affecting unregulated gas retail sales.
At
December 31, 2006 and 2005, the market values of these contracts and the book
value of weather contracts were not significant.
Interest
Rate Management
The
Company is exposed to interest rate risk associated with its borrowing
arrangements. Its risk management program seeks to reduce the potentially
adverse effects that market volatility may have on interest expense. The Company
has used interest rate swaps and treasury locks to hedge forecasted debt
issuances and other interest rate swaps to manage interest rate exposure.
Hedging instruments are recorded at market value. Changes in market value,
when
effective, are recorded in Accumulated
other comprehensive income
for cash
flow hedges, as an adjustment to the outstanding debt balance for fair value
hedges, or as regulatory asset/liability when regulation is involved. Amounts
are recorded to interest expense as settled.
Interest
rate swaps hedging the fair value of fixed-rate debt with a total notional
amount of $17.5 million are outstanding. The fair value liability associated
with those swaps was $0.3 million at December 31, 2006 and $0.6 million at
December 31, 2005. At December 31, 2006, an approximate $2.8 million net
regulatory liability remains. Of that net liability, $0.6 million will be
reclassified to earnings in 2007, $0.7 million was reclassified to earnings
in
2006, and $0.6 million was reclassified to earnings during both 2005 and
2004.
Fair
Value of Other Financial Instruments
The
carrying values and estimated fair values of the Company's other financial
instruments follow:
|
At
December 31,
|
|||||||||||||
|
2006
|
2005
|
||||||||||||
|
(In
millions)
|
Carrying
Amount
|
|
Est.
Fair Value
|
|
Carrying
Amount
|
|
Est.
Fair Value
|
||||||
|
Long-term
debt
|
$
|
1,256.3
|
$
|
1,276.1
|
$
|
1,256.9
|
$
|
1,312.9
|
|||||
|
Short-term
borrowings & notes payable
|
464.8
|
464.8
|
299.9
|
299.9
|
|||||||||
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.
Under
current regulatory treatment, call premiums on reacquisition of long-term debt
are generally recovered in customer rates over the life of the refunding issue
or over a 15-year period. Accordingly, any reacquisition would not be expected
to have a material effect on the Company's results of operations.
Periodically,
the Company tests its cost method investments and notes receivable for
impairment which may require their fair value to be estimated. Because of the
customized nature of these investments and lack of a readily available market,
it is not practical to estimate the fair value of these financial instruments
at
specific dates without considerable effort and costs. At December 31, 2006,
and
2005, the fair value for these financial instruments was not estimated.
| 16. |
Segment
Reporting
|
The
Company segregates its operations into three groups: 1) Utility Group, 2)
Nonutility Group, and 3) Corporate and Other.
The
Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which
consist of the Company’s regulated operations and other operations that provide
information technology and other support services to those regulated operations.
The Company segregates its regulated operations into a Gas Utility Services
operating segment and an Electric Utility Services operating segment. The Gas
Utility Services segment provides natural gas distribution and transportation
services to nearly two-thirds of Indiana and to west central Ohio. The Electric
Utility Services segment provides electric distribution services primarily
to
southwestern Indiana, and includes the Company’s power generating and marketing
operations. The Company cross manages its regulated operations as separated
between Energy Delivery, which includes the gas and electric transmission and
distribution functions, and Power Supply, which includes the power generating
and marketing operations. In total, regulated operations supply natural gas
and
/or electricity to over one million customers. In total, the Utility Group
has
three operating segments of as defined by SFAS 131 “Disclosure About Segments of
an Enterprise and Related Information” (SFAS 131).
The
Nonutility Group is comprised of one operating segment as defined by SFAS 131
that includes various subsidiaries and affiliates investing in energy marketing
and services, coal mining, and energy infrastructure services, among other
energy-related opportunities.
Corporate
and Other includes unallocated corporate expenses such as branding and
charitable contributions, among other activities, that benefit the Company’s
other operating segments. Net income is the measure of profitability used by
management for all operations. Information related to the Company’s business
segments is summarized below:
|
Year
Ended December 31,
|
|||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
||||||||
|
Revenues
|
|||||||||||||
| Utility Group | |||||||||||||
|
Gas
Utility Services
|
$
|
1,232.5
|
$
|
1,359.7
|
$
|
1,126.2
|
|||||||
|
Electric
Utility Services
|
422.2
|
421.4
|
371.3
|
||||||||||
|
Other
Operations
|
36.6
|
36.1
|
32.9
|
||||||||||
|
Eliminations
|
(34.8
|
)
|
(35.4
|
)
|
(32.4
|
)
|
|||||||
|
Total
Utility Group
|
1,656.5
|
1,781.8
|
1,498.0
|
||||||||||
|
Nonutility
Group
|
503.2
|
344.3
|
272.1
|
||||||||||
|
Eliminations
|
(118.1
|
)
|
(98.1
|
)
|
(80.3
|
)
|
|||||||
|
Consolidated
Revenues
|
$
|
2,041.6
|
$
|
2,028.0
|
$
|
1,689.8
|
|||||||
|
Profitability
Measures - Net Income
|
|||||||||||||
|
Gas
Utility Services
|
$
|
41.5
|
$
|
34.7
|
$
|
28.1
|
|||||||
|
Electric
Utility Services
|
41.6
|
50.4
|
47.9
|
||||||||||
|
Other
Operations
|
8.3
|
10.0
|
7.1
|
||||||||||
|
Utility
Group Net Income
|
|
91.4
|
|
95.1
|
|
83.1
|
|||||||
|
Nonutility
Group Net Income
|
18.1
|
48.2
|
26.4
|
||||||||||
|
Corporate
& Other Net Loss
|
(0.7
|
)
|
(6.5
|
)
|
(1.6
|
)
|
|||||||
|
Consolidated
Net Income
|
$
|
108.8
|
$ |
136.8
|
$
|
107.9
|
|||||||
|
Year
Ended December 31,
|
||||||||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|||||||||||
|
Amounts
Included in Profitability Measures
|
||||||||||||||||
| Depreciation & Amortization |
|
|||||||||||||||
| Utility Group |
|
|||||||||||||||
|
Gas
Utility Services
|
$
|
67.6
|
$
|
64.9
|
$
|
57.0
|
||||||||||
|
Electric
Utility Services
|
61.8
|
56.9
|
53.3
|
|||||||||||||
|
Other
Operations
|
21.9
|
19.5
|
17.5
|
|||||||||||||
|
Total
Utility Group
|
151.3
|
141.3
|
127.8
|
|||||||||||||
|
Nonutility
Group
|
21.0
|
16.0
|
12.0
|
|||||||||||||
|
Corporate
& Other
|
-
|
0.9
|
0.3
|
|||||||||||||
|
Consolidated
Depreciation & Amortization
|
$
|
172.3
|
$
|
158.2
|
$
|
140.1
|
||||||||||
|
Year
Ended December 31,
|
||||||||||||||||
|
(In
millions)
|
2006
|
2005
|
2004
|
|||||||||||||
|
Interest
Expense
|
||||||||||||||||
|
Utility
Group
|
||||||||||||||||
|
Gas
Utility Services
|
$
|
40.7
|
$
|
40.2
|
$
|
41.4
|
||||||||||
|
Electric
Utility Services
|
28.6
|
23.7
|
21.3
|
|||||||||||||
|
Other
Operations
|
8.2
|
6.0
|
4.7
|
|||||||||||||
|
Total
Utility Group
|
77.5
|
69.9
|
67.4
|
|||||||||||||
|
Nonutility
Group
|
20.0
|
14.6
|
11.3
|
|||||||||||||
|
Corporate
& Other
|
(1.9
|
)
|
(0.6
|
)
|
(1.0
|
)
|
||||||||||
|
Consolidated
Interest Expense
|
$
|
95.6
|
$
|
83.9
|
77.7
|
|||||||||||
|
Equity
in Earnings of Unconsolidated Affiliates
|
||||||||||||||||
|
Utility
Group: Other Operations
|
$
|
-
|
$
|
-
|
$
|
0.2
|
||||||||||
|
Nonutility
Group
|
17.0
|
45.6
|
20.4
|
|||||||||||||
|
Consolidated
Equity in Earnings of Unconsolidated Affiliates
|
$
|
17.0
|
$
|
45.6
|
$
|
20.6
|
||||||||||
|
Income
Taxes
|
||||||||||||||||
|
Utility
Group
|
||||||||||||||||
|
Gas
Utility Services
|
$
|
22.6
|
$
|
22.3
|
$
|
17.5
|
||||||||||
|
Electric
Utility Services
|
25.3
|
33.5
|
30.8
|
|||||||||||||
|
Other
Operations
|
(0.2
|
)
|
1.7
|
4.8
|
||||||||||||
|
Total
Utility Group
|
47.7
|
57.5
|
53.1
|
|||||||||||||
|
Nonregulated
Group
|
(17.6
|
)
|
(9.9
|
)
|
(13.6
|
)
|
||||||||||
|
Corporate
& Other
|
0.2
|
(3.5
|
)
|
(0.5
|
)
|
|||||||||||
|
Consolidated
Income Taxes
|
$
|
30.3
|
$
|
44.1
|
$
|
39.0
|
||||||||||
|
Capital
Expenditures
|
||||||||||||||||
|
Utility
Group
|
||||||||||||||||
|
Gas
Utility Services
|
$
|
76.8
|
$
|
81.0
|
$
|
89.1
|
||||||||||
|
Electric
Utility Services
|
156.8
|
100.0
|
150.6
|
|||||||||||||
|
Other
Operations
|
24.8
|
29.9
|
27.9
|
|||||||||||||
|
Non-cash
costs & changes in accruals
|
(11.8
|
)
|
3.6
|
(25.4
|
)
|
|||||||||||
|
Total
Utility Group
|
246.6
|
214.5
|
242.2
|
|||||||||||||
|
Nonutility
Group
|
34.8
|
17.1
|
10.3
|
|||||||||||||
|
Consolidated
Capital Expenditures
|
$
|
281.4
|
$
|
231.6
|
$
|
252.5
|
||||||||||
|
Investments
in Equity Method Investees
|
||||||||||||||||
|
Nonutility
Group
|
$
|
16.7
|
$
|
19.2
|
$
|
18.2
|
||||||||||
|
At
December 31,
|
||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|||||||
|
Assets
|
||||||||||
| Utility Group |
|
|||||||||
|
Gas
Utility Services
|
$
|
1,953.6
|
$
|
2,030.8
|
||||||
|
Electric
Utility Services
|
1,277.6
|
1,176.0
|
||||||||
|
Other
Operations
|
225.9
|
188.9
|
||||||||
|
Eliminations
|
(16.3
|
)
|
(5.6
|
)
|
||||||
|
Total
Utility Group
|
3,440.8
|
3,390.1
|
||||||||
|
Nonutility
Group
|
639.7
|
542.4
|
||||||||
|
Corporate
& Other
|
466.7
|
369.1
|
||||||||
|
Eliminations
|
(455.6
|
)
|
(433.5
|
)
|
||||||
|
Consolidated
Assets
|
$
|
4,091.6
|
$
|
3,868.1
|
||||||
| 17. |
Additional
Operational & Balance Sheet
Information
|
Prepayments
and other current assets
in the
Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Prepaid
gas delivery service
|
$
|
66.2
|
$
|
69.3
|
|||
|
Utilicom
receivable - current
|
44.6
|
-
|
|||||
|
Fair
market value of derivative instruments
|
15.6
|
2.6
|
|||||
|
Prepaid
taxes
|
12.3
|
5.3
|
|||||
|
Deferred
income taxes
|
3.6
|
-
|
|||||
|
Other
prepayments & current assets
|
30.4
|
29.2
|
|||||
|
Total
prepayments & other current assets
|
$
|
172.7
|
$
|
106.4
|
|||
Accrued
liabilities
in the
Consolidated Balance Sheets consist of the following:
|
At
December 31,
|
|||||||
|
(In
millions)
|
2006
|
|
2005
|
||||
|
Refunds
to customers & customer deposits
|
$
|
43.0
|
$
|
36.7
|
|||
|
Accrued
taxes
|
31.6
|
34.2
|
|||||
|
Accrued
interest
|
16.8
|
17.2
|
|||||
|
Deferred
income taxes
|
-
|
7.6
|
|||||
|
Accrued
salaries & other
|
55.8
|
60.9
|
|||||
|
Total
accrued liabilities
|
$
|
147.2
|
$
|
156.6
|
|||
Other
- net
in the
Consolidated Statements of Income consists of the following:
|
Year
Ended December 31,
|
||||||||||
|
(In
millions)
|
2006
|
|
2005
|
|
2004
|
|||||
|
AFUDC
& capitalized interest
|
$
|
5.3
|
$
|
2.5
|
$
|
4.6
|
||||
|
Interest
income
|
4.0
|
3.8
|
3.0
|
|||||||
|
Synfuel-related
activity
|
(11.4
|
)
|
(1.9
|
)
|
-
|
|||||
|
Broadband
charges
|
(1.9
|
)
|
(1.1
|
)
|
(6.0
|
)
|
||||
|
Gain/loss
on sale of investments
|
(0.6
|
)
|
(0.1
|
)
|
0.4
|
|||||
|
All
other income
|
1.9
|
3.0
|
2.6
|
|||||||
|
Total
other – net
|
$
|
(2.7
|
)
|
$
|
6.2
|
$
|
4.6
|
|||
| 18. |
Quarterly
Financial Data (Unaudited)
|
Information
in any one quarterly period is not indicative of annual results due to the
seasonal variations common to the Company’s utility operations. Summarized
quarterly financial data for 2006 and 2005 follows:
|
(In
millions, except per share amounts)
|
Q1
|
Q2
|
Q3
|
Q4
|
|||||||||
|
2006
|
|||||||||||||
|
Operating
revenues
|
$
|
774.5
|
$
|
317.5
|
$
|
340.5
|
$
|
609.1
|
|||||
|
Operating
income
|
91.5
|
28.5
|
28.4
|
72.1
|
|||||||||
|
Net
income
|
57.6
|
4.3
|
12.0
|
34.9
|
|||||||||
|
Earnings
per share:
|
|||||||||||||
|
Basic
|
$
|
0.76
|
$
|
0.06
|
$
|
0.16
|
$
|
0.46
|
|||||
|
Diluted
|
0.76
|
0.06
|
0.16
|
0.45
|
|||||||||
|
2005
|
|||||||||||||
|
Operating
revenues
|
$
|
677.2
|
$
|
326.2
|
$
|
310.8
|
$
|
713.8
|
|||||
|
Operating
income
|
95.2
|
29.2
|
29.9
|
58.8
|
|||||||||
|
Net
income
|
56.1
|
13.4
|
16.5
|
50.8
|
|||||||||
|
Earnings
per share:
|
|||||||||||||
|
Basic
|
$
|
0.74
|
$
|
0.18
|
$
|
0.22
|
$
|
0.67
|
|||||
|
Diluted
|
0.74
|
0.18
|
0.22
|
0.66
|
|||||||||
| 19. |
Impact
of Recently Issued Accounting Guidance
|
SFAS
No. 157
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS
157). SFAS 157 defines fair value, establishes a framework for measuring fair
value in generally accepted accounting principles (GAAP), and expands
disclosures about fair value measurements. This statement does not require
any
new fair value measurements; however, the standard will impact how other fair
value based GAAP is applied. SFAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007, and interim periods
within those fiscal years with early adoption encouraged. The
Company is currently assessing the impact this statement will have on its
financial statements and results of operations.
FIN
48
In
June
2006, the FASB issued FASB Interpretation No. 48 (FIN 48) “Accounting for
Uncertainty in Income Taxes” an interpretation of SFAS 109, Accounting for
Income Taxes. FIN 48 prescribes a recognition threshold and measurement
attribute for financial statement recognition and measurement of tax positions
taken or expected to be taken in an income tax return. FIN 48 also provides
guidance related to reversal of tax positions, balance sheet classification,
interest and penalties, interim period accounting, disclosure and transition.
The interpretation is effective for fiscal years beginning after December
15,
2006. The adoption of this standard is not expected to have a material impact
on
operating results or financial condition.
ITEM
9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM
9A.
CONTROLS AND PROCEDURES
Changes
in Internal Controls over Financial Reporting
During
the quarter ended December 31, 2006, there have been no changes to the Company’s
internal controls over financial reporting that have materially affected, or
are
reasonably likely to materially affect, the Company’s internal control over
financial reporting.
Conclusion
Regarding the Effectiveness of Disclosure Controls and
Procedures
As
of
December 31, 2006, the Company conducted an evaluation under the supervision
and
with the participation of the Chief Executive Officer and Chief Financial
Officer of the effectiveness and the design and operation of the Company's
disclosure controls and procedures. Based on that evaluation, the Chief
Executive Officer and the Chief Financial Officer have concluded that the
Company's disclosure controls and procedures are effective as of December 31,
2006, to ensure that the information required to be disclosed and filed or
submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and forms.
Management’s
Report on Internal Control over Financial Reporting
Vectren
Corporation’s management is responsible for establishing and maintaining
adequate internal control over financial reporting. Under the supervision and
with the participation of management, including the Chief Executive Officer
and
Chief Financial Officer, the Company conducted an evaluation of the
effectiveness of its internal control over financial reporting based on the
framework in Internal
Control - Integrated Framework issued
by
the Committee of Sponsoring Organizations of the Treadway Commission. Based
on
that evaluation under the framework in Internal
Control — Integrated Framework,
the
Company concluded that its internal control over financial reporting was
effective as of December 31, 2006.
Management’s
assessment of the effectiveness of internal control over financial reporting
as
of December 31, 2006, has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in their report which
is included in Item 8 of this annual report.
ITEM
9B. OTHER INFORMATION
None.
PART
III
ITEM
10. DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The
information required by Part III, Item 10 of this Form 10-K is incorporated
by
reference herein, and made part of this Form 10-K, from the Company's definitive
Proxy Statement for its 2007 Annual Meeting of Stockholders, which will be
filed
with the Securities and Exchange Commission pursuant to Regulation 14A, within
120 days after the end of the fiscal year. The Company’s executive officers are
the same as those named executive officers detailed in the Proxy Statement.
The
Company’s Corporate Governance Guidelines, its charters for each of its Audit,
Compensation and Benefits and Nominating and Corporate Governance Committees,
and its Code of Ethics covering the Company’s directors, officers and employees
are available on the Company’s website, www.vectren.com,
and a
copy will be mailed upon request to Investor Relations, Attention: Steve Schein,
One Vectren Square, Evansville, Indiana 47708. The Company intends to disclose
any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf
of the Company’s directors or officers including, but not limited to, the
principal executive officer, principal financial officer, principal accounting
officer or controller and persons performing similar functions on the Company’s
website at the internet address set forth above promptly following the date
of
such amendment or waiver and such information will also be available by mail
upon request to Investor Relations, Attention: Steve Schein, One Vectren Square,
Evansville, Indiana 47708.
ITEM
11. EXECUTIVE COMPENSATION
Information
required by Part III, Item 11 of this Form 10-K is incorporated by reference
herein, and made part of this Form 10-K, from the Company's definitive Proxy
Statement for its 2007 Annual Meeting of Stockholders, which will be filed
with
the Securities and Exchange Commission pursuant to Regulation 14A, within 120
days after the end of the fiscal year.
ITEM
12. SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Except
with respect to equity compensation plan information of the Registrant, which
is
included herein, the information required by Part III, Item 12 of this Form
10-K
is incorporated by reference herein, and made part of this Form 10-K, from
the
Company's definitive Proxy Statement for its 2007 Annual Meeting of
Stockholders, which will be filed with the Securities and Exchange Commission
pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
Shares
Issuable under Share-Based Compensation Plans
As
of
December 31, 2006, the following shares were authorized to be issued under
share-based compensation plans:
|
A
|
B
|
C
|
|||||||||||||||||
|
Plan
category
|
Number
of securities to be issued upon exercise of outstanding options,
warrants
and rights
|
Weighted
average exercise price of outstanding options, warrants and
rights
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a)
|
||||||||||||||||
|
Equity
compensation plans approved by
|
|||||||||||||||||||
|
security
holders
|
1,963,985
|
(1
|
)
|
$
|
23.33
|
(1
|
)
|
2,823,947
|
(2
|
)
|
|||||||||
|
Equity
compensation plans not approved
|
|||||||||||||||||||
|
by
security holders
|
-
|
-
|
-
|
||||||||||||||||
|
Total
|
1,963,985
|
$
|
23.33
|
2,823,947
|
|||||||||||||||
| (1) |
Includes
the following Vectren Corporation Plans: Vectren Corporation At-Risk
Compensation Plan and 1994 SIGCORP Stock Option
Plan.
|
| (2) |
Future
issuances of shares awards can only be made under the Vectren Corporation
At-Risk Plan. Shares available for issuance under the At-Risk Plan
have
been reduced by the issuance of 167,100 restricted shares approved
by the
board of directors’ Compensation Committee, effective January 1,
2007.
|
The
SIGCORP stock option plan was approved by SIGCORP common shareholders prior
to
the merger forming Vectren. The At-Risk Compensation plan was approved by
Vectren Corporation common shareholders after the merger forming
Vectren.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AND DIRECTOR INDEPENDENCE
Information
required by Part III, Item 13 of this Form 10-K is incorporated by reference
herein, and made part of this Form 10-K, from the Company's definitive Proxy
Statement for its 2007 Annual Meeting of Stockholders, which will be filed
with
the Securities and Exchange Commission pursuant to Regulation 14A, within 120
days after the end of the fiscal year.
ITEM
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information
required by Part III, Item 14 of this Form 10-K is incorporated by reference
herein, and made part of this Form 10-K, from the Company's definitive Proxy
Statement for its 2007 Annual Meeting of Stockholders, which will be filed
with
the Securities and Exchange Commission pursuant to Regulation 14A, within 120
days after the end of the fiscal year.
PART
IV
ITEM
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
List
of
Documents Filed as Part of This Report
Consolidated
Financial Statements
The
consolidated financial statements and related notes, together with the report
of
Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and
Supplementary Data” of this Form 10-K. The financial statements of ProLiance
Energy, LLC are attached as exhibit 99.1 to this Form 10-K.
Supplemental
Schedules
For
the
years ended December 31, 2006, 2005, and 2004, the Company’s Schedule II --
Valuation and Qualifying Accounts Consolidated Financial Statement Schedules
is
presented herein. The report of Deloitte & Touche LLP on the schedule may be
found in Item 8. All other schedules are omitted as the required information
is
inapplicable or the information is presented in the Consolidated Financial
Statements or related notes in Item 8.
SCHEDULE
II
Vectren
Corporation and Subsidiaries
VALUATION
AND QUALIFYING ACCOUNTS AND RESERVES
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
|
|
Column
D
|
|
Column
E
|
||||||
|
Additions
|
||||||||||||||||
|
|
Balance
at
|
|
Charged
|
|
Charged
|
|
Deductions
|
|
Balance
at
|
|
||||||
|
|
|
Beginning
|
|
to
|
|
to
Other
|
|
from
|
|
End
of
|
|
|||||
|
Description
|
|
of
Year
|
|
Expenses
|
|
Accounts
|
|
Reserves,
Net
|
|
Year
|
||||||
|
(In
millions)
|
||||||||||||||||
|
VALUATION
AND QUALIFYING ACCOUNTS:
|
||||||||||||||||
|
Year
2006 – Accumulated provision for
|
||||||||||||||||
|
uncollectible accounts
|
$
|
2.8
|
$
|
15.3
|
$
|
-
|
$
|
15.0
|
$
|
3.1
|
||||||
|
Year
2005 – Accumulated provision for
|
||||||||||||||||
|
uncollectible
accounts
|
$
|
2.0
|
$
|
15.1
|
$
|
-
|
$
|
14.3
|
$
|
2.8
|
||||||
|
Year
2004 – Accumulated provision for
|
||||||||||||||||
|
uncollectible accounts
|
$
|
3.2
|
$
|
11.9
|
$
|
-
|
$
|
13.1
|
$
|
2.0
|
||||||
|
OTHER
RESERVES:
|
||||||||||||||||
|
Year
2006 – Restructuring costs
|
$
|
2.4
|
$
|
-
|
$
|
-
|
$
|
0.7
|
$
|
1.7
|
||||||
|
Year
2005 – Restructuring costs
|
$
|
2.7
|
$
|
-
|
$
|
-
|
$
|
0.3
|
$
|
2.4
|
||||||
|
Year
2004 – Restructuring costs
|
$
|
3.2
|
$
|
-
|
$
|
-
|
$
|
0.5
|
$
|
2.7
|
||||||
List
of Exhibits
The
Company has incorporated by reference herein certain exhibits as specified
below
pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company
attached to this filing filed electronically with the SEC are listed below.
Exhibits for the Company are listed in the Index to Exhibits beginning on page
94.
Vectren
Corporation
Form
10-K
Attached
Exhibits
The
following Exhibits are included in this Annual Report on Form 10-K.
|
Exhibit
Number
|
Document
|
|
31.1
|
Chief
Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Chief
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
32
|
Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
The
following Exhibits were filed electronically with the SEC with this filing.
|
Exhibit
Number
|
Document
|
|
21.1
|
List
of Company’s Significant Subsidiaries
|
|
23.1
|
Consent
of Independent Registered Public Accounting Firm
|
|
23.2
|
Consent
of Independent Auditors
|
|
99.1
|
ProLiance
Energy, LLC Consolidated Financial
Statements
|
INDEX
TO EXHIBITS
2.
Plan of Acquisition, Reorganization, Arrangement, Liquidation or
Succession
| 2.1 |
Asset
Purchase Agreement dated December 14, 1999 between Indiana Energy,
Inc.
and The Dayton Power and Light Company and Number-3CHK with a commitment
letter for a 364-Day Credit Facility dated December 16,1999. (Filed
and
designated in Current Report on Form 8-K dated December 28, 1999,
File No.
1-9091, as Exhibit 2 and 99.1)
|
3.
Articles of Incorporation and By-Laws
| 3.1 |
Amended
and Restated Articles of Incorporation of Vectren Corporation effective
March 31, 2000. (Filed and designated in Current Report on Form 8-K
filed
April 14, 2000, File No. 1-15467, as Exhibit
4.1.)
|
| 3.2 |
Amended
and Restated Code of By-Laws of Vectren Corporation as of February
1,
2007. (Filed and designated in Current Report on Form 8-K filed February
5, 2007, File No. 1-15467, as Exhibit 3.2.)
|
| 3.3 |
Shareholders
Rights Agreement dated as of October 21, 1999 between Vectren Corporation
and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated
in Form S-4 (No. 333-90763), filed November 12. 1999, File No. 1-15467,
as
Exhibit 4.)
|
4.
Instruments Defining the Rights of Security Holders, Including
Indentures
| 4.1 |
Mortgage
and Deed of Trust dated as of April 1, 1932 between Southern Indiana
Gas
and Electric Company and Bankers Trust Company, as Trustee, and
Supplemental Indentures thereto dated August 31, 1936, October 1,
1937,
March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January
1,
1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1,
1966,
August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October
1,
1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981,
January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984,
November
1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and
designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in
Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit
(b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form
8-K,
File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553,
dated
March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated
June 3,
1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and
designated in Form 10-K, for the fiscal year 1985, File No. 1-3553,
as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and
designated in Form 10-K, for the fiscal year 1986, File No. 1-3553,
as
Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K,
for
the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December
13, 1990.
(Filed and designated in Form 10-K, for the fiscal year 1990, File
No.
1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in
Form 8-K,
dated April 13, 1993, File No. 1-3553, as Exhibit 4.) June 1, 1993
(Filed
and designated in Form 8-K, dated June 14, 1993, File No. 1-3553,
as
Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for
the
fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999.
(Filed
and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553,
as
Exhibit 4(a).) March 1, 2000. (Filed and designated in Form 10-K
for the
year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.)
August 1,
2004. (Filed designated in Form 10-K for the year ended December
31, 2004,
File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed designated
in
Form 10-K for the year ended December 31, 2004, File No. 1-15467,
as
Exhibit 4.2.)
|
| 4.2 |
Indenture
dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National
Association (formerly know as First Trust National Association, which
was
formerly know as Bank of America Illinois, which was formerly know
as
Continental Bank, National Association. Inc.'s. (Filed and designated
in
Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.);
First Supplemental Indenture thereto dated as of February 15, 1991.
(Filed
and designated in Current Report on Form 8-K filed February 15, 1991,
File
No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto
dated
as of September 15, 1991, (Filed and designated in Current Report
on Form
8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).);
Third
supplemental Indenture thereto dated as of September 15, 1991 (Filed
and
designated in Current Report on Form 8-K filed September 25, 1991,
File
No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto
dated
as of December 2, 1992, (Filed and designated in Current Report on
Form
8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth
Supplemental Indenture thereto dated as of December 28, 2000, (Filed
and
designated in Current Report on Form 8-K filed December 27, 2000,
File No.
1-6494, as Exhibit 4.)
|
| 4.3 |
Indenture
dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana
Gas
Company, Inc., Southern Indiana Gas and Electric Company, Vectren
Energy
Delivery of Ohio, Inc., and U.S. Bank Trust National Association.
(Filed and designated in Form 8-K, dated October 19, 2001, File No.
1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October
19,
2001, between Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc.,
Southern Indiana Gas and Electric Company, Vectren Energy Delivery
of
Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated October 19, 2001, File No. 1-16739,
as
Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility
Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and
Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S.
Bank
Trust National Association. (Filed and designated in Form 8-K, dated
November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental
Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery
of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and
designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as
Exhibit
4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings,
Inc.,
Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company,
Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National
Association. (Filed and designated in Form 8-K, dated November 18,
2005, File No. 1-16739, as Exhibit 4.1). Form of Fifth Supplemental
Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company,
Inc., Southern Indiana Gas & Electric Company, Vectren Energy Delivery
of Ohio, Inc., and U.S. Bank Trust National Association. (Incorporated
by reference to Exhibit 4.1 to the Current Report on Form 8-K, dated
October 16, 2006, File No.
1-16739).
|
| 4.4 |
Note
purchase agreement, dated October 11, 2005, between Vectren Capital
Corp.
and each of the purchasers named therein. (Filed designated in Form
10-K
for the year ended December 31, 2005, File No. 1-15467, as Exhibit
4.4.)
|
10.
Material Contracts
| 10.1 |
Summary
description of Southern Indiana Gas and Electric Company's nonqualified
Supplemental Retirement Plan (Filed and designated in Form 10-K for
the
fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First Amendment,
effective April 16, 1997 (Filed and designated in Form 10-K for the
fiscal
year 1997, File No. 1-3553, as Exhibit
10.29.).
|
| 10.2 |
Southern
Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and
designated in Southern Indiana Gas and Electric Company's Proxy Statement
dated February 22, 1994, File No. 1-3553, as Exhibit
A.)
|
| 10.3 |
Indiana
Energy, Inc. Unfunded Supplemental Retirement Plan for a Select Group
of
Management Employees as amended and restated effective December 1,
1998.
(Filed and designated in Form 10-Q for the quarterly period ended
December
31, 1998, File No. 1-9091, as Exhibit
10-G.)
|
| 10.4 |
Vectren
Corporation At Risk Compensation Plan effective May 1, 2001,(as amended
and restated s of May 1, 2006). (Filed and designated in Vectren
Corporation’s Proxy Statement dated March 15, 2006, File No. 1-15467, as
Appendix H.)
|
| 10.5 |
Vectren
Corporation Non-Qualified Deferred Compensation Plan, as amended
and
restated effective January 1, 2001. (Filed and designated in Form
10-K,
for the year ended December 31, 2001, File No. 1-15467, as Exhibit
10.32.)
|
| 10.6 |
Vectren
Corporation Change in Control Agreement between Vectren Corporation
and
Niel C. Ellerbrook dated as of March 1, 2005. (Filed and designated
in
Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit
99.1.)
|
| 10.7 |
Vectren
Corporation At Risk Compensation Plan specimen Restricted Stock Grant
Agreement for officers, effective January 1, 2005. (Filed and designated
in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit
99.1.)
|
| 10.8 |
Vectren
Corporation At Risk Compensation Plan specimen restricted stock grant
agreement for officers, effective January 1, 2006. (Filed and designated
in Form 8-K, dated February 27, 2006, File No. 1-15467, as Exhibit
99.1.)
|
| 10.9 |
Vectren
Corporation At Risk Compensation Plan specimen Stock Option Grant
Agreement for officers, effective January 1, 2005. (Filed and designated
in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit
99.2.)
|
| 10.10 |
Vectren
Corporation specimen employment agreement dated February 1, 2005.
(Filed
and designated in Form 8-K, dated February 1, 2005, File No. 1-15467,
as
Exhibit 99.1.)
|
| 10.11 |
Life
Insurance Replacement Agreement between Vectren Corporation and certain
named officers, effective December 31, 2006. (Filed and designated
in Form
8-K, dated December 31, 2006, File No. 1-15467 as Exhibit
99.1.)
|
| 10.12 |
Gas
Sales and Portfolio Administration Agreement between Indiana Gas
Company,
Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed
and
designated in Form 10-K, for the year ended December 31, 2003, File
No.
1-15467, as Exhibit 10.15.)
|
| 10.13 |
Gas
Sales and Portfolio Administration Agreement between Southern Indiana
Gas
and Electric Company and ProLiance Energy, LLC, effective September
1,
2002. (Filed and designated in Form 10-K, for the year ended December
31,
2003, File No. 1-15467, as Exhibit 10.16.)
|
| 10.14 |
Coal
Supply Agreement for F.B. Culley Generating Station between Southern
Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December
17, 1997 and effective January 1, 1998. (Filed and designated in
Form
10-K, for the year ended December 31, 2003, File No. 1-15467, as
Exhibit
10.18.) Portions of the document have been omitted pursuant to a
request
to a request for confidential treatment. Amendment 1, effective January
1,
2003, to Coal Supply Agreement between Southern Indiana Gas and Electric
Company and Vectren Fuels, Inc originally dated December 17, 1997.
(Filed
and designated in Form 10-K, for the year ended December 31, 2003,
File
No. 1-15467, as Exhibit 10.19.)
|
| 10.15 |
Coal
Supply Agreement for Generating Stations at Yankeetown, Warrick County,
Indiana, and West Franklin, Posey County, Indiana between Southern
Indiana
Gas and Electric Company and Vectren Fuels, Inc., dated January 19,
2000.
(Filed and designated in Form 10-K, for the year ended December 31,
2003,
File No. 1-15467, as Exhibit 10.20.) Amendment 1, effective January
1,
2004, to Coal Supply Agreement between Southern Indiana Gas and Electric
Company and Vectren Fuels, Inc originally dated January 19, 2000.
(Filed
and designated in Form 10-K, for the year ended December 31, 2003,
File
No. 1-15467, as Exhibit 10.21.)
|
| 10.16 |
Formation
Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc.,
IGC
Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke
Utility, Citizens Energy Services Corporation and ProLiance Energy,
LLC,
effective March 15, 1996. (Filed and designated in Form 10-Q for
the
quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit
10-C.)
|
| 10.17 |
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among
Vectren
Utility Holdings, Inc., and each of the purchasers named therein.
(Filed
and designated in Form 10-K, for the year ended December 31, 2005,
File
No. 1-15467, as Exhibit 10.24.)
|
| 10.18 |
Revolving
Credit Agreement (5 year facility), dated November 10, 2005, among
Vectren
Capital Corp., and each of the purchasers named therein. (Filed and
designated in Form 10-K, for the year ended December 31, 2005, File
No.
1-15467, as Exhibit 10.25.)
|
21.
Subsidiaries of the Company
The
list
of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.
23.
Consents of Experts and Counsel
The
consents of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 and
23.2.
31.
Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of
2002
Chief
Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act Of 2002 is attached hereto as Exhibit 31.1
Chief
Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act Of 2002 is attached hereto as Exhibit 31.2
32.
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
Certification
Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto
as
Exhibit 32
99.1
ProLiance Energy, LLC Consolidated Financial Statements for the Fiscal Years
Ended September 30, 2006, 2005, and 2004. (Filed
herewith.)
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) 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
Dated
February 16, 2007
/s/
Niel C. Ellerbrook
Niel
C.
Ellerbrook,
Chairman,
President, Chief Executive Officer, and Director
Pursuant
to the requirements of the Securities and Exchange Act of 1934, this report
has
been signed below by the following persons on behalf of the Registrant and
in
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||
|
/s/
Niel C. Ellerbrook
|
Chairman,
President, Chief
Executive
Officer, &
|
February
16, 2007
|
||
|
Niel
C. Ellerbrook
|
Director
(Principal Executive
Officer)
|
|||
|
/s/
Jerome A. Benkert, Jr.
|
Executive
Vice President &
|
February
16, 2007
|
||
|
Jerome
A. Benkert, Jr.
|
Chief
Financial Officer
(Principal
Financial Officer)
|
|||
|
/s/
M. Susan Hardwick
|
Vice
President, Controller &
Assistant
Treasurer
|
February
16, 2007
|
||
|
M.
Susan Hardwick
|
(Principal
Accounting Officer)
|
|||
|
/s/
John M. Dunn
|
Director
|
February
16, 2007
|
||
|
John
M. Dunn
|
||||
|
/s/
John D. Engelbrecht
|
Director
|
February
16, 2007
|
||
|
John
D. Engelbrecht
|
||||
|
/s/
Anton H. George
|
Director
|
February
16, 2007
|
||
|
Anton
H. George
|
||||
|
/s/
Robert L. Koch II
|
Director
|
February
16, 2007
|
||
|
Robert
L. Koch II
|
||||
|
/s/
William G Mays
|
Director
|
February
16, 2007
|
||
|
William
G. Mays
|
||||
|
/s/
J. Timothy McGinley
|
Director
|
February
16, 2007
|
||
|
J.
Timothy McGinley
|
||||
|
/s/
Richard P. Rechter
|
Director
|
February
16, 2007
|
||
|
Richard
P. Rechter
|
||||
|
/s/
R. Daniel Sadlier
|
Director
|
February
16, 2007
|
||
|
R.
Daniel Sadlier
|
||||
|
/s/
Richard W. Shymanski
|
Director
|
February
16, 2007
|
||
|
Richard
W. Shymanski
|
||||
|
/s/
Michael L Smith
|
Director
|
February
16, 2007
|
||
|
Michael
L Smith
|
||||
|
/s/
Jean L Wojtowicz
|
Director
|
February
16, 2007
|
||
|
Jean
L.Wojtowicz
|
-95-